<PAGE>
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended September 30, 1996
Commission File Number 1-14174
AGL RESOURCES INC.
(Exact name of registrant as specified in its charter)
Georgia 58-2210952
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
303 Peachtree Street, N.E.,
Atlanta, Georgia
30308
(Address and zip code of 404-584-9470
principal executive offices) (Registrant's telephone number,
including area code)
Securities registered pursuant to Section 12(b) of the Act:
Common Stock, $5 Par Value New York Stock Exchange
Preferred Share Purchase Rights New York Stock Exchange
(Title of Class) (Name of exchange on which registered)
Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months, and (2) has been subject to such filing requirements
for the past 90 days. Yes X No
Aggregate market value of the voting stock held by non-affiliates of the
registrant, computed by reference to the closing price of such stock as of
November 29,1996: $1,177,590,035.
The number of shares of Common Stock outstanding as of November 29, 1996 was
55,743,907 shares.
DOCUMENTS INCORPORATED BY REFERENCE:
Portions of the 1996 Annual Report to Shareholders for AGL Resources Inc. for
the fiscal year ended September 30, 1996, are incorporated herein by reference
in Part II and portions of the Proxy Statement for the 1997 Annual Meeting of
Shareholders are incorporated herein by reference in Part III.
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
<PAGE>
TABLE OF CONTENTS
Page
PART I
Item 1. Business............................................. 1
Item 2. Properties........................................... 13
Item 3. Legal Proceedings.................................... 13
Item 4. Submission of Matters to a Vote of
Security Holders................................... 15
Item 4.(A). Executive Officers of the Registrant................. 16
PART II
Item 5. Market for the Registrant's Common Equity
and Related Stockholder Matters.................... 17
Item 6. Selected Financial Data.............................. 17
Item 7. Management's Discussion and Analysis of
Results of Operations and Financial Condition...... 17
Item 8. Financial Statements and Supplementary Data.......... 17
Item 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure............. 17
PART III
Item 10. Directors and Executive Officers of the
Registrant......................................... 18
Item 11. Executive Compensation............................... 18
Item 12. Security Ownership of Certain Beneficial
Owners and Management.............................. 18
Item 13. Certain Relationships and Related Transactions....... 18
PART IV
Item 14. Exhibits, Financial Statement Schedules
and Reports on Form 8-K............................ 19
Signatures ...................................................... 21
<PAGE>
Part I
- --------------------------------------------------------------------------------
Item 1. Business
GENERAL
AGL Resources Inc. (AGL Resources) is a Georgia corporation incorporated
on November 27, 1995, for the primary purpose of becoming the holding company
for Atlanta Gas Light Company (AGLC), a natural gas distribution utility, and
its subsidiaries. Unless noted specifically or otherwise required by the
context, references to AGL Resources include AGLC, AGLC's wholly owned natural
gas utility subsidiary, Chattanooga Gas Company (Chattanooga), and AGL
Resources' nonregulated subsidiaries: AGL Energy Services, Inc. (AGL Energy
Services); AGL Investments, Inc. (AGL Investments); AGL Resources Service
Company (Service Company); and The Energy Spring, Inc. AGL Energy Services has
one nonregulated subsidiary, Georgia Gas Company. AGL Investments has six
nonregulated subsidiaries: Georgia Gas Service Company; Georgia Energy Company;
AGL Consumer Services, Inc.; AGL Gas Marketing, Inc.; AGL Power Services, Inc.;
and Trustees Investments, Inc. Unless noted specifically or otherwise required
by the context, references to AGLC include the operations and activities of AGLC
and Chattanooga.
AGL Resources' principal business is the distribution of natural gas to
customers in central, northwest, northeast and southeast Georgia and the
Chattanooga, Tennessee area through its natural gas distribution subsidiary,
AGLC. AGLC's major service area is the ten county metropolitan Atlanta area.
Metropolitan Atlanta has an estimated population of 3 million, constituting
approximately 41% of the total population of Georgia. Approximately 66% of
AGLC's customers are located in the Atlanta metropolitan area. These customers
consume 48% of the natural gas sold and transported and provide approximately
60% of the gas revenues of AGLC. AGLC's other principal service areas in Georgia
are the Athens, Augusta, Brunswick, Macon, Rome, Savannah and Valdosta areas.
During the fiscal year ended September 30, 1996, AGLC supplied natural gas
service to an average of approximately 1.3 million customers in Georgia
including 516 centrally metered customers serving 50,098 apartment units. AGLC
provides natural gas service in 235 cities and surrounding areas in Georgia. In
addition to AGLC's service areas in Georgia, natural gas service was supplied by
Chattanooga to an average of approximately 52,000 customers in Chattanooga and
Cleveland, Tennessee, and surrounding portions of Hamilton County and Bradley
County, Tennessee during the fiscal year ended September 30, 1996. All of AGLC's
natural gas service area is certificated by the Georgia Public Service
Commission (Georgia Commission) and the Tennessee Regulatory Authority (TRA),
formerly the Tennessee Public Service Commission.
The areas served by AGLC in Georgia outside the metropolitan areas
described in the preceding paragraph were for many years primarily agricultural,
with timber, poultry, cattle, cotton, tobacco, peanuts and soy beans among the
principal products. However, both industry and agriculture are currently
important to the economies of these areas. In addition to the industries that
use local natural resources such as pulpwood, clay, marble, talc and kaolin,
AGLC serves a number of nationally known organizations that operate
installations in Georgia. These operations increase substantially the
diversification of industry in AGLC's service area.
During fiscal 1996, AGLC added approximately 41,500 customers, based on
12-month average calculations, representing an increase over the prior year of
approximately 3%. Substantially all of this growth was in the residential and
small commercial service categories.
The ten largest customers of AGLC accounted for 1.9% and 1.4% of AGL
Resources' total operating revenues and operating margin, respectively, for the
fiscal year ended September 30, 1996. For the same period, volumes of gas sold
and transported to the ten largest customers accounted for 10.6% of total
volumes of gas sold and transported.
AGL Resources' consolidated operating revenues during the fiscal year
ended September 30, 1996, were $1.2 billion, of which approximately 58% was
derived from residential utility customers, 24% from commercial utility
customers, 14% from industrial utility customers, 2% from transportation
customers and 2% from other sources.
1
<PAGE>
AGL Resources engages in nonregulated business activities through its
wholly owned subsidiaries, AGL Energy Services, a gas supply services company;
AGL Investments, a subsidiary established to develop and manage certain
nonregulated businesses; The Energy Spring, Inc., a retail energy marketing
company; Service Company and their subsidiaries.
During August 1995 AGLC signed an agreement with Sonat Inc. (Sonat) to
form a joint venture to acquire the business of Sonat Marketing Company, a
wholly owned subsidiary of Sonat. The joint venture, Sonat Marketing Company
L.P. (Sonat Marketing), offers natural gas sales, transportation, risk
management and storage services to natural gas users and producers in key
natural gas producing and consuming areas of the United States.
AGLC invested $32.6 million in exchange for a 35% ownership interest in
Sonat Marketing. During the third quarter of fiscal 1996, AGLC's interest in
Sonat Marketing was transferred to AGL Gas Marketing, Inc., a wholly owned
subsidiary of AGL Investments. AGL Investments has certain rights for a period
of five years to sell its interest in Sonat Marketing to Sonat at a
predetermined fixed price, as defined, or for fair market value at any time.
During June 1996 Sonat Power Marketing, Inc. and AGL Power Services,
Inc., a wholly owned subsidiary of AGL Investments (AGL Power Services), formed
a joint venture, Sonat Power Marketing, L.P. AGL Power Services invested
approximately $1 million in exchange for a 35% ownership interest in the
partnership. Sonat Power Marketing L.P. provides power marketing and all related
services in key market areas throughout the United States.
In addition to its predominant business of natural gas distribution and
its investments in joint ventures, AGL Resources, through wholly owned
subsidiaries, serves approximately 14,000 customers in Georgia and Alabama
through retail propane sales (Georgia Gas Service Company), and has minor
interests in natural gas production activities (Georgia Gas Company) and real
estate holdings (Trustees Investments, Inc.). The aggregate net income
contributed by nonregulated operations in fiscal 1996 was $3.9 million. See Part
I, Item 1, "Business - Subsidiaries."
Through September 30, 1996, historic maximum daily sendout of natural gas
was approximately 2.15 billion cubic feet which occurred on February 4, 1996.
The mean temperature in the metropolitan Atlanta area that day was 11(degree) F.
AGL Resources' primary business of gas distribution through AGLC is highly
seasonal in nature and heavily dependent on weather because of the substantial
use of gas for heating purposes. However, the Georgia Commission and the TRA
have authorized the implementation of weather normalization adjustment riders,
which are designed to offset the impact that either unusually cold or unusually
warm weather has on operating margin, earnings and cash flow and are designed to
stabilize operating margin and earnings at the levels which would occur with
normal weather. For the effects of seasonal variations on quarterly earnings,
see Note 14 in Notes to Consolidated Financial Statements in AGL Resources' 1996
Annual Report to Shareholders.
On September 30, 1996, AGL Resources and its subsidiaries had 2,952
employees. Approximately 640 employees working for AGLC and 55 employees working
for Service Company are covered by provisions of collective bargaining
agreements with the General Teamsters Local Union No. 528. The master agreement,
among the Teamsters, AGLC and Service Company, provides for a $1,000 lump sum
payment to each covered employee in October 1996 and a $500 lump sum payment in
September 1997 and 1998. In addition, the pay ranges for all covered positions
are scheduled to increase 3% in September 1997 and 1998 and 3.5% in 1999. Based
on current pay levels, it is anticipated that few covered employees will see any
base rate increases until 1999. That agreement expires September 17, 2000.
A five-year collective bargaining agreement among AGLC, Service Company
and the International Union of Operating Engineers, Local Union No. 474,
covering 60 employees in Savannah, Georgia, was ratified on November 14, 1996.
The contract provides for a $1,000 lump sum payment to each covered employee in
November 1996 and a $500 lump sum payment in November 1997 and 1998. In
addition, the pay ranges for all covered positions are scheduled to increase 3%
in September 1997 and 1998, 3.5% in 1999, and 3% in the year 2000. Based on
current pay levels, it is anticipated that few covered employees will see any
base rate increases until 1998. That agreement expires November 4, 2001.
2
<PAGE>
Additionally, AGLC has approximately 60 employees at its Chattanooga and
Cleveland, Tennessee facilities covered by an agreement with the Utility Workers
Union of America, Local Union No. 461. A new five-year agreement with the
Utility Workers became effective October 15, 1996. The agreement provides for a
$1,000 lump sum payment to each covered employee in November 1996 and a $500
lump sum payment in October 1997 and 1998. In addition, the pay ranges for all
covered positions are scheduled to increase 3% in September 1997 and 1998, 3.5%
in 1999, and 3% in the year 2000. Based on current pay levels, it is anticipated
that few covered employees will see any base rate increases until 1998. That
agreement expires October 14, 2001.
AGLC holds franchises, permits, certificates and rights which management
believes are sufficient for the operation of its properties without any
substantial restrictions and adequate for the operation of its gas distribution
business.
SUBSIDIARIES
As a result of the formation of the holding company, ownership of
nonregulated businesses was transferred from AGLC to various subsidiaries of AGL
Resources. Ownership of Georgia Gas Company (natural gas production activities)
has been transferred to AGL Energy Services. Ownership of Georgia Energy Company
(natural gas vehicle conversions), Georgia Gas Service Company (retail propane
sales) and Trustees Investments, Inc. (real estate holdings) has been
transferred to AGL Investments. AGLC's interest in Sonat Marketing Company L.P.
has been transferred to AGL Gas Marketing, Inc., a wholly owned subsidiary of
AGL Investments. In addition, AGL Investments has established two wholly owned
subsidiaries: AGL Power Services, which owns a 35% interest in Sonat Power
Marketing, L.P., and AGL Consumer Services, Inc., an energy-related consumer
products and services company. Service Company was formed during fiscal 1996 to
provide corporate support services to AGL Resources and its subsidiaries.
Expenses of Service Company are allocated to AGL Resources and its subsidiaries.
SUBSEQUENT EVENT
During December 1996, AGL Resources signed a letter of intent with
Transcontinental Gas Pipe Line Corporation (Transco) to form a joint venture,
which would be known as Cumberland Pipeline Company, to operate and market
interstate pipeline capacity. The transaction is subject to various corporate
and regulatory approvals.
Initially, the 135-mile Cumberland pipeline will consist of existing
pipeline infrastructure owned by the two companies. Projected to enter service
by November 1, 2000, Cumberland will provide service to AGLC, Chattanooga and
other markets throughout the eastern Tennessee Valley.
Affiliates of Transco and AGL Resources each will own 50% of the new
pipeline company, and an affiliate of Transco will serve as operator. The
project will be submitted to the Federal Energy Regulatory Commission for
approval in the fourth quarter of 1997.
The remainder of this page was intentionally left blank.
3
<PAGE>
<TABLE>
<CAPTION>
Gas Sales and Statistics
FOR THE YEARS ENDED SEPTEMBER 30
1996 1995 1994 1993 1992
- ---------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Operating Revenues (Millions of Dollars)
Sales of gas
Residential ................................. $ 708.8 $ 610.6 $ 700.7 $ 658.2 $ 575.7
Commercial .................................. 288.8 243.2 285.8 268.1 231.5
Industrial .................................. 178.8 169.4 172.1 154.2 140.9
Transportation revenues ....................... 21.5 23.9 22.6 33.8 36.6
Miscellaneous revenues ........................ 19.7 15.9 18.7 16.0 9.9
- ---------------------------------------------------------------------------------------------------------------------
Total utility operating revenues .............. 1,217.6 1,063.0 1,199.9 1,130.3 994.6
- ---------------------------------------------------------------------------------------------------------------------
Other operating revenues ...................... 2.6
- ---------------------------------------------------------------------------------------------------------------------
Total operating revenues .................. $ 1,220.2 $ 1,063.0 $ 1,199.9 $ 1,130.3 $ 994.6
=====================================================================================================================
Utility Throughput
Therms sold (Millions)
Residential ................................ 1,165.4 916.8 1,003.1 1,001.4 915.4
Commercial ................................. 538.2 454.0 478.9 478.5 433.9
Industrial ................................. 449.6 526.0 424.8 388.7 445.0
- ---------------------------------------------------------------------------------------------------------------------
Therms transported ............................ 738.7 722.8 697.4 795.6 901.8
- ---------------------------------------------------------------------------------------------------------------------
Total utility throughput .................. 2,891.9 2,619.6 2,604.2 2,664.2 2,696.1
=====================================================================================================================
Average Utility Customers (Thousands)
Residential ................................... 1,289.4 1,250.4 1,215.2 1,182.7 1,152.2
Commercial .................................... 102.5 100.0 98.0 95.7 93.7
Industrial .................................... 2.6 2.6 2.5 2.5 2.5
- ---------------------------------------------------------------------------------------------------------------------
Total ..................................... 1,394.5 1,353.0 1,315.7 1,280.9 1,248.4
=====================================================================================================================
Sales, Per Average Residential Customer
Gas sold (Therms) ............................. 904 733 825 847 794
Revenue (Dollars) ............................. 550.00 488.32 576.61 556.52 499.65
Revenue per therm (Cents) ..................... 60.8 66.6 69.9 65.7 62.9
Degree Days - Atlanta Area
30-year normal ................................ 2,991 2,991 2,991 3,021 3,021
Actual ........................................ 3,191 2,121 2,565 2,852 2,552
Percentage of actual to 30-year normal ........ 106.7 70.9 85.8 94.4 84.5
Gas Account (Millions of Therms)
Natural gas purchased ......................... 1,632.9 1,406.9 1,453.6 1,629.9 1,555.4
Natural gas withdrawn from storage ............ 596.0 520.7 500.3 276.4 263.3
Gas transported ............................... 738.7 722.8 697.4 795.6 901.8
- ---------------------------------------------------------------------------------------------------------------------
Total send-out ............................ 2,967.6 2,650.4 2,651.3 2,701.9 2,720.5
Less
Unaccounted for ............................. 60.4 20.4 37.2 29.0 16.2
Company use ................................. 15.3 10.4 9.9 8.7 8.2
- ---------------------------------------------------------------------------------------------------------------------
Sold and transported to utility customers . 2,891.9 2,619.6 2,604.2 2,664.2 2,696.1
=====================================================================================================================
Cost of Gas (Millions of Dollars)
Natural gas purchased ......................... $ 547.1 $ 389.4 $ 550.1 $ 595.7 $ 487.9
Natural gas withdrawn from storage ............ 171.6 182.4 186.7 105.3 102.6
- ---------------------------------------------------------------------------------------------------------------------
Cost of gas - utility operations .............. 718.7 571.8 736.8 701.0 590.5
Cost of gas - other ........................... 1.6
- ---------------------------------------------------------------------------------------------------------------------
Total cost of gas ......................... $ 720.3 $ 571.8 $ 736.8 $ 701.0 $ 590.5
=====================================================================================================================
Utility Plant - End of Year (Millions of Dollars)
Gross plant ................................... $ 1,969.0 $ 1,919.9 $ 1,833.2 $ 1,740.6 $ 1,634.8
Net plant ..................................... $ 1,361.2 $ 1,336.6 $ 1,279.6 $ 1,217.9 $ 1,157.4
Gross plant investment per customer
(Thousands of Dollars) ...................... $ 1.4 $ 1.4 $ 1.4 $ 1.4 $ 1.3
Capital Expenditures (Millions of Dollars) ...... $ 132.5 $ 121.7 $ 122.5 $ 122.2 $ 132.9
Gas Mains - Miles of 3" Equivalent .............. 29,045 28,520 27,972 27,390 26,936
Employees - Average ............................. 2,942 3,249 3,764 3,764 3,794
Average Btu Content of Gas ...................... 1,024 1,027 1,032 1,027 1,024
=====================================================================================================================
</TABLE>
4
<PAGE>
GAS SUPPLY SERVICES, PRICING AND COMPETITION
General
AGLC is served directly by four interstate pipelines: Southern Natural Gas
Company (Southern), South Georgia Natural Gas Company (South Georgia),
Transcontinental Gas Pipe Line Corporation (Transco) and East Tennessee Natural
Gas Company (East Tennessee), in combination with its upstream pipeline,
Tennessee Gas Pipeline Company (Tennessee) ,the parent company and primary
source of gas for East Tennessee.
As a result of Order 636, gas purchasing decisions made by local
distribution companies (LDCs) are subject to greater review by state regulatory
commissions. Leglislation was enacted by the Georgia General Asembly in 1994
which provides for annual review and approval by the Georgia Commission of
AGLC's gas services portfolio on a prospective basis. On August 1, 1996, AGLC
made its annual gas supply plan filing for fiscal 1997 and on September 13,
1996, the Georgia Commission issued its order approving the mix of gas services
in the portfolio.
Firm Pipeline Transportation and Underground Storage
The table on the following page shows the amount of firm transportation
and describes the types and amounts of underground storage that both AGLC and
Chattanooga have elected or been assigned under Order 636. The table also shows
services that were not affected by the implementation of Order 636.
The remainder of this page was intentionally left blank.
5
<PAGE>
<TABLE>
<CAPTION>
Production Area Supplemental
Underground Underground
Maximum Storage Storage
Firm Maximum Maximum
Transportation Withdrawal Withdrawal Expiration
Mcf/Day Mcf/Day(1) Mcf/Day(2) Date
------- ------- ------- -------
ATLANTA GAS LIGHT COMPANY
- -------------------------
<S> <C> <C> <C> <C>
Southern
Firm Transportation 1,000 June 30, 2007
Firm Transportation 604,857 February 28, 1999
Firm Transportation 45,272 February 29, 2000
Firm Transportation 110,905 April 30, 2007
CSS 382,089 February 28, 1999
CSS 24,133 February 29, 2000
ANR - 50 113,000 March 31, 2003
ANR - 100 55,500 March 31, 2003
Transco
Firm Transportation 107,600 March 31, 2010
Firm Transportation 15,000 July 1, 2005
Firm Transportation 6,222 March 17, 2008
Firm Transportation 4,500 October 31, 2009
WSS 70,588 March 31, 2010
Eminence Storage 11,263 March 31, 1997
Eminence Storage 19,034 October 31, 2013(3)
GSS 57,016 June 30, 2001(3)
GSS 67,919 March 31, 2013(3)
LSS 17,430 March 31, 1994(4)
SS-1 20,211 March 31, 2009
LGA 41,522 October 31, 1991(4)
Cove Point LNG 66,667 April 15, 1997
Other 14,493 March 31, 2001
Other 4,831 March 31, 1997
Tennessee/East Tennessee
Firm Transportation 62,000 November 1, 2000(3)
FS Storage 29,485 November 1, 2000
CNG 3,321 March 31, 2001
South Georgia
Firm Transportation 11,877 April 30, 2007
ANR - 100 708 March 31, 2003
CSS 6,764 February 28, 1998
------- ------- -------
Total 969,233 546,677 459,297
======= ======= =======
CHATTANOOGA GAS COMPANY
- -----------------------
Southern
Firm Transportation 4,649 February 28, 2000
Firm Transportation 14,051 February 28, 2000
Firm Transportation 3,300 April 30, 2007
CSS 14,051 February 28, 2000
Tennessee/East Tennessee
Firm Transportation 45,000 November 1, 2000(3)
FS Storage 20,802 November 1, 2000
CNG 2,411 March 31, 2001
------- -------
Total 67,000 37,264
======= =======
(1) Production area storage requires a complementary amount of the firm
transportation capacity identified in the first column to move storage gas
withdrawals to AGLC's service area.
(2) Supplemental underground storage withdrawals include delivery to AGLC's
service area and do not require any of the firm transportation capacity
identified in the first column. Injections into supplemental " underground
storage require incremental transportation, primarily from transportation
identified in Column 1."
(3) Expiration dates are shown for these contracts although contracts have not
yet been executed. AGLC is operating under Natural Gas Act (NGA) certificate
authority while negotiating these contracts.
(4) AGLC is operating under NGA certificate authority while negotiating these
contracts.
</TABLE>
6
<PAGE>
Wellhead Supply
AGLC and Chattanooga have entered into firm wellhead supply contracts to
purchase 442,973 Mcf/day and 27,427 Mcf/day, respectively, of their firm
transportation and underground storage requirements. AGLC anticipates entering
into additional firm wellhead supply contracts by the end of December 1996 to
purchase up to 58,851 Mcf/day for AGLC and 6,342 Mcf/day for Chattanooga. AGLC
also purchases spot market gas as needed during the year.
Liquefied Natural Gas
To meet the demand for natural gas on the coldest days of the winter
months, AGLC must also maintain sufficient supplemental quantities of liquefied
natural gas (LNG) in its supply portfolio. AGLC's three strategically located
Georgia-based LNG plants -- north and south of Atlanta and near Macon --
currently provide a combined maximum daily supplement of 665,000 Mcf and a
combined usable storage capacity of 72 million gallons, equivalent to 6,214,921
Mcf. This combined maximum daily supplement is expected to increase to 765,000
Mcf in January 1997 with the installation of additional equipment at the LNG
plant north of Atlanta. Chattanooga's LNG plant provides a maximum daily
supplement of 90,000 Mcf and has a usable storage capacity of 13 million
gallons, equivalent to 1,207,574 Mcf.
Competition
AGLC competes to supply natural gas to interruptible customers who are
capable of switching to alternative fuels, including propane, fuel and waste
oils, electricity and, in some cases, combustible wood by-products. AGLC also
competes to supply gas to interruptible customers who might seek to bypass its
distribution system.
AGLC can price distribution services to interruptible customers four
ways. First, multiple rates are established under the rate schedules of AGLC's
tariff approved by the Georgia Commission. If an existing tariff rate does not
produce a price competitive with a customer's relevant competitive alternative,
three alternate pricing mechanisms exist: Negotiated Contracts, Interruptible
Transportation and Sales Maintenance (ITSM) discounts and Special Contracts.
On February 17, 1995, the Georgia Commission approved a settlement that
permits AGLC to negotiate contracts with customers who have the option of
bypassing AGLC's facilities (Bypass Customers) to receive natural gas from other
suppliers. The bypass avoidance contracts (Negotiated Contracts) can be
renewable, provided the initial term does not exceed five years, unless a longer
term specifically is authorized by the Georgia Commission. The rate provided by
the Negotiated Contract may be lower than AGLC's filed rate, but not less than
AGLC's marginal cost of service to the potential Bypass Customer. Service
pursuant to a Negotiated Contract may commence without Georgia Commission
action, after a copy of the contract is filed with the Georgia Commission.
Negotiated Contracts may be rejected by the Georgia Commission within 90 days of
filing; absent such action, however, the Negotiated Contracts remain in effect.
None of the Negotiated Contracts filed to date with the Georgia Commission have
been rejected.
The settlement also provides for a bypass loss recovery mechanism to
operate until the earlier of September 30, 1998, or the effective date of new
rates for AGLC resulting from a general rate case. Under the recovery mechanism,
AGLC is allowed to recover from other customers 75% of the difference between
(a) the nongas cost revenue that was received from the potential Bypass Customer
during the most recent 12-month period and (b) the nongas cost revenue that is
calculated to be received from the lower Negotiated Contract rate applied to the
same volumetric level. Concerning the remaining 25% of the difference, AGLC is
allowed to retain a 44% share of capacity release revenues in excess of $5
million until AGLC is made whole for discounts from Negotiated Contracts. To the
extent there are additional capacity release revenues, AGLC is allowed to retain
15% of such amounts.
In addition to Negotiated Contracts, which are designed to serve existing
and potential Bypass Customers, AGLC's ITSM Rider continues to permit discounts
for short-term transactions to compete with alternative fuels. Revenue
shortfalls, if any, from interruptible customers as measured by the test-year
interruptible revenues
7
<PAGE>
determined by the Georgia Commission in AGLC's 1993 rate case will continue to
be recovered under the ITSM Rider.
The settlement approved by the Georgia Commission also provides that AGLC
may file contracts (Special Contracts) for Georgia Commission approval if the
service cannot be provided through the ITSM Rider, existing rate schedules, or
Negotiated Contract procedures. A Special Contract, for example, could involve
AGLC providing a long-term service contract to compete with alternative fuels
where physical bypass is not the relevant competition.
Pursuant to the approved settlement, AGLC has filed and is providing
service pursuant to 46 Negotiated Contracts. Additionally, the Georgia
Commission has approved Special Contracts between AGLC and five interruptible
customers.
For additional information regarding competitive initiatives in Georgia,
see Part I, Item 1, "Business - State Regulatory Matters."
On July 22, 1996, Chattanooga filed a plan with the TRA that permits
Chattanooga to negotiate contracts with customers in Tennessee who have
long-term competitive options, including bypass. On November 7, 1996, the TRA
hearing officer recommended approval of a settlement that permits Chattanooga to
negotiate contracts with large commercial or industrial customers who are
capable of bypassing Chattanooga's distribution system. The settlement provides
for approval on an experimental basis, with the TRA to review the measure two
years from the approval date. The pricing terms provided in any such contract
may be neither less than Chattanooga's marginal cost of providing service nor
greater than the filed tariff rate generally applicable to such service.
Chattanooga can recover 50% of the difference between the contract rate and the
applicable tariff rate through the balancing account of the purchased gas
adjustment provisions of Chattanooga's rate schedules.
FEDERAL REGULATORY MATTERS
Order 636
On July 16, 1996, the United States Court of Appeals for the District of
Columbia Circuit (D.C. Circuit) issued its ruling in UNITED DISTRIBUTION COS. V.
FERC, concerning the appeals from Order No. 636, which mandated the unbundling
of interstate pipeline sales service and established new open access
transportation regulations. The court generally upheld the Federal Energy
Regulatory Commission's (FERC) orders against a broad array of challenges, but
remanded the orders to the FERC for reconsideration of certain issues, including
the FERC's decision to permit pipelines to pass all of their gas supply
realignment (GSR) costs through to their customers and its decision to require
interruptible transportation customers to bear 10% of GSR costs. The FERC has
not yet issued an order on remand, and thus it is not known whether the FERC
will change its GSR policies. On October 29, 1996, the D.C. Circuit rejected
requests for rehearing filed by AGLC and others, which sought reversal of the
court's ruling affirming the FERC's authority over capacity release by LDCs. The
court's order is subject to possible further proceedings before the United
States Supreme Court.
AGLC, based on filings with FERC by its pipeline suppliers, currently
estimates that its portion of transition costs, costs that previously were
recovered in the pipelines' rate for bundled sales services, from all of its
pipeline suppliers would be approximately $109.9 million. Such filings currently
are pending before FERC for final approval, and the transition costs are being
collected subject to refund. Approximately $80.6 million of such costs have been
incurred by AGLC as of September 30, 1996, and are being recovered from its
customers under the purchased gas provisions of AGLC's rate schedules.
Transition costs have not affected the total cost of gas to AGLC's customers
significantly because (1) AGLC purchases its wellhead gas supplies based on
market prices that are below the cost of gas previously embedded in the bundled
pipelines' sales service rates and (2) many elements of transition costs
previously were embedded in the rates for the pipelines' bundled sales service.
See Part I, Item 1, "State Regulatory Matters - Gas Supply Filing" in this Form
10-K for further discussion of recovery of gas costs.
Details concerning the status of the Order 636 restructuring proceedings
involving the pipelines that serve AGLC directly are set forth below.
8
<PAGE>
SOUTHERN
Restructuring Proceeding.
AGLC has filed several petitions for review with the D. C. Circuit
concerning various aspects of Southern's restructuring. Those aspects include
favorable treatment of small customers, rate mitigation, mitigation of GSR
costs, and tying of firm storage service to firm transportation service. AGLC
has moved to withdraw those petitions for review in light of the FERC's approval
of the restructuring settlement between Southern and its customers, as discussed
below, but the court has not yet acted on AGLC's motion.
GSR Cost Recovery Proceeding.
On April 11, 1996, the FERC issued an order constituting final approval of
the settlement agreement between AGLC, Southern, and other customers which
resolves virtually all pending Southern proceedings before the FERC and the
courts. The settlement resolves Southern's pending general rate proceedings,
which relate to Southern's rates charged from January 1, 1991, through the
present. The settlement provides for rate reductions and refund offsets against
GSR costs. It also resolves Southern's Order No. 636 transition cost proceedings
and provides for revisions to Southern's tariff. The FERC's approval of the
settlement is subject to action on petitions for review filed by parties
opposing the settlement.
On April 25, 1996, the FERC issued an order accepting Southern's March 29,
1996, filing to reduce its volumetric GSR surcharge for consenting parties to
the restructuring settlement to reflect actual GSR costs incurred by Southern
through December 31, 1995. Southern continues to make quarterly and monthly
transition cost filings to recover costs from contesting parties to the
settlement, and the FERC has ordered that such costs may be recovered by
Southern, subject to the outcome of a hearing for contesting parties. However,
GSR and other transition cost charges to AGLC are in accordance with the
settlement. Assuming the FERC's approval of the settlement is upheld on judicial
review, AGLC's share of Southern's transition costs is estimated to be $85.5
million. This estimate would not be affected by the remand of Order No. 636,
unless FERC's approval of the settlement is not upheld on judicial review. As of
September 30, 1996, $70.9 million of such costs have already been incurred by
AGLC.
TENNESSEE
Restructuring Proceeding.
AGLC has filed several petitions for review with the D. C. Circuit
concerning various aspects of Tennessee's restructuring. Those aspects include
favorable treatment for small customers, rate mitigation and others. AGLC also
has filed a petition for review of FERC orders concerning Tennessee's service
obligation to AGLC. AGLC's petitions for review currently are pending with the
court.
GSR Cost Recovery Proceeding.
Tennessee has made several quarterly GSR recovery filings. AGLC's estimated
liability as a result of Tennessee's prior GSR recovery filings is approximately
$16.8 million, assuming that the FERC does not change its GSR policies pursuant
to the Order No. 636 remand and subject to possible reduction based on the
hearing FERC established to investigate Tennessee's costs. AGLC is actively
participating in Tennessee's GSR cost recovery proceeding. As of September 30,
1996, $5.4 million of such costs have been incurred by AGLC.
Columbia Gas Transmission Corporation.
AGLC has filed a petition for review of a FERC order approving a settlement
between Tennessee and Columbia Gas Transmission Corporation (Columbia). The
settlement resolves issues relating to Columbia's upstream capacity on
Tennessee's system, as well as certain other matters between the two pipelines.
AGLC has sought review of the order on the ground that the FERC has failed to
ensure that Tennessee's customers will be made whole with respect to Tennessee's
agreement to permit Columbia to abandon certain contracts for capacity on
Tennessee's system.
FERC Rate Proceedings
AGLC also is participating in various rate proceedings before the FERC
involving applications for rate changes filed by its pipeline suppliers. To the
extent that these cases have not been settled, as described below, the rates
filed in these proceedings have been accepted, and made effective subject to
refund and the outcome of the FERC proceedings.
9
<PAGE>
SOUTHERN
As noted above, the FERC has approved the restructuring settlement
agreement between AGLC, Southern, and other customers that resolves all issues
between AGLC and Southern for Southern's outstanding rate proceedings.
SOUTH GEORGIA
On December 20, 1995, the FERC issued an order upholding an initial
decision by an administrative law judge (ALJ) in South Georgia's rate case that
South Georgia's interruptible transportation (IT) rate should be based on a load
factor of 100% on a prospective basis. AGLC supported the 100% load factor IT
rate at the hearing in this proceeding. No party has sought rehearing of the
FERC's ruling, which is therefore final.
TENNESSEE
On April 5, 1996, Tennessee filed with the FERC a comprehensive settlement
to resolve all issues in its current rate case. The settlement provides for a
reduction of approximately $83 million in the cost of service underlying
Tennessee's rates in effect since July 1, 1995, and also provides for Tennessee
to share a portion of costs associated with firm capacity relinquished by its
customers. AGLC filed comments supporting the settlement. AGLC's estimated
annual reduction in cost is $2.2 million. The FERC approved the proposed
settlement on October 30, 1996, but the order approving the settlement is
pending requests for rehearing and therefore is not yet final.
On July 3, 1996, the FERC issued an order on exceptions from the rulings of
an ALJ in a prior Tennessee rate case. Among other things, the FERC's order,
which is to have prospective effect, rejects a proposal to unbundle Tennessee's
production area rates from its market area rates. AGLC supported the unbundling
proposal. The order also upholds the ALJ's ruling that Tennessee's interruptible
transportation rates should be set at the 100% load factor derivative of the
firm transportation rate. AGLC supported the 100% load factor proposal. The
order also rejects proposals to revise Tennessee's rate zone boundaries. AGLC
has opposed such proposals. The FERC's rulings may impact the rates contained in
the settlement agreement in Tennessee's FERC rate case, which was approved by
the FERC on November 1, 1996. The FERCs order approving the settlement is
pending requests for rehearing and therefore is not yet final.
TRANSCO
On June 19, 1996, Transco filed a proposed partial settlement to resolve
cost of service and throughput issues in its current rate case. The partial
settlement reserves certain cost allocation and rate design issues for hearing,
including roll-in of Transco's incrementally priced Leidy Line facilities and
Transco's use of the straight-fixed-variable rate design methodology. The
proposal provides for a reduction of approximately $58 million in the cost of
service underlying Transco's rates that have been in effect since September 1,
1995. The estimated annual reduction in costs to AGLC is $2.4 million. AGLC
filed comments in support of the proposed settlement, which was approved by the
FERC on November 1, 1996. The FERC's order approving the settlement is pending
requests for rehearing and therefore is not yet final.
On July 3, 1996, the FERC issued an order on exceptions from the rulings of
an ALJ in a prior Transco rate case. Among other things, the FERC's order, which
is to have prospective effect, rejects Transco's proposal to established a
firm-to-the-wellhead production area rate design, but permits Transco to file a
rate case to establish firm-to-the-wellhead rates if customers with entitlements
to production area capacity are permitted to determine whether they require such
capacity in an open season. AGLC opposed Transco's firm-to-the-wellhead
proposal. The order also reverses the ALJ's ruling that Transco must establish a
separate production area cost of service. AGLC had filed exceptions seeking
reversal of this aspect of the ALJ's ruling. AGLC has joined other Transco
customers in seeking rehearing of the July 3, 1996 order with respect to the
FERC's determination that Transco may file a new proposal to establish
firm-to-the-wellhead rates, and also has sought clarification that the FERC's
order does not eliminate protections against abandonment that originated in the
settlements by which AGLC and other customers agreed to convert from sales to
firm transportation service.
On November 1, 1996, Transco filed to increase its rates by approximately
$83 million over the last rates approved by the FERC. Among other things,
Transco filed its own proposal to roll into systemwide rates the costs of the
incrementally-priced Leidy Line and Southern Expansion facilities on a
prospective basis, after a hearing. AGLC filed a protest challenging the roll-in
proposal and the magnitude of the requested rate increase. On November 29, 1996,
the FERC issued an order accepting Transco's filing, subject to refund and a
hearing, and consolidated Transco's roll-in proposal with its ongoing rate case,
where a Leidy Line roll-in proposal by other parties is being litigated.
10
<PAGE>
ANR PIPELINE
ANR Pipeline (ANR) provides transportation services to Southern under a
case-specific certificate issued by the FERC in 1980. Southern entered into this
transportation arrangement with ANR in order to provide Southern's customers,
including AGLC, access to storage facilities owned and operated by ANR Storage
Company. According to Southern, approximately 96% of Southern's service
entitlement on ANR is used to serve AGLC. AGLC has actively participated in the
hearing procedures established by the FERC with respect to ANR's general rate
proceeding, supporting a reduced transportation rate for ANR's services to
Southern. That proceeding currently is pending for decision before an ALJ.
Miscellaneous
SECONDARY MARKETS
On July 31, 1996, the FERC issued a notice of proposed rulemaking
concerning changes to the FERC's regulations governing release of firm pipeline
capacity, as well as the sale by pipelines of interruptible transportation and
short-term firm capacity. The FERC is not proposing to eliminate the prohibition
against pricing released capacity at higher than the pipeline's maximum tariff
rate for firm service. However, the FERC has solicited applications from
pipelines and local distribution companies to participate in a pilot program in
which the prices for released firm capacity, interruptible transportation, and
short-term firm capacity are not capped. AGLC has not sought permission to
participate in the pilot program, but is monitoring the process. One of AGLC's
pipeline suppliers, Transco, sought approval to participate in the pilot
program, but the FERC rejected Transco's application.
NEGOTIATED RATES
The FERC has issued a policy statement authorizing pipelines to establish
mechanisms by which they may charge separately negotiated rates to particular
customers in lieu of their tariff rates. The FERC has required pipelines to
retain in their tariffs a "recourse rate," which must be approved by the FERC,
and which must be available to those customers that do not choose to separately
negotiate a rate with the pipeline. Of the pipelines that supply AGLC, Transco,
Tennessee, and East Tennessee have requested authority to separately negotiate
rates. The FERC has approved the applications by Transco, Tennessee, and the
application filed by East Tennessee. The FERC's policy statement has been
appealed to the D. C. Circuit, and AGLC has intervened in that proceeding.
Arcadian
The FERC has granted final approval to the settlement between Southern
and Arcadian Corporation (Arcadian); see Part I, Item 3, "Legal Proceedings."
The settlement resolves both Arcadian's FERC complaint against Southern and
Arcadian's antitrust lawsuit against Southern and AGLC. The settlement provides
for Southern to provide firm transportation service to Arcadian at a negotiated
rate for an initial term of five years ending October 31, 1998. In addition, the
settlement establishes tariff language addressing the conditions under which
Southern will address future requests for direct transportation service. AGLC
sought rehearing of the FERC's order approving the settlement but the FERC
rejected AGLC's rehearing request on November 26, 1996. AGLC had petitioned for
review of the FERC's prior orders in this proceeding in the United States Court
of Appeals for the Eleventh Circuit. AGLC's appeals have been held in abeyance
pending action by the FERC on AGLC's rehearing request. If the FERC's orders
approving the restructuring settlement between Southern, AGLC and the other
customers are upheld on appeal, it will resolve the undue discrimination issue
raised by AGLC in Southern's current rate case.
On April 22, 1996, AGLC filed to withdraw portions of its request for
rehearing of the FERC's order approving the November 12, 1993, settlement
between Arcadian and Southern. The portions of the request for rehearing that
AGLC proposes to withdraw, pursuant to the restructuring settlement with
Southern, are those that allege that Southern's discounted rates to Arcadian
constitute an anticompetitive "price squeeze" against AGLC.
AGLC cannot predict the outcome of these federal proceedings nor
determine the ultimate effect, if any, such proceedings may have on AGLC.
STATE REGULATORY MATTERS
Atlanta Gas Light Company
REGULATORY REFORM INITIATIVES
Two regulatory reform initiatives are pending in Georgia, both designed
to increase competition and reduce the role of regulation within the natural gas
industry. The first such initiative is the subject of a proceeding at the
Georgia Commission; the second initiative is before study committees of the
Georgia General Assembly.
11
<PAGE>
With respect to the first initiative, on November 20, 1995, the Georgia
Commission issued a Natural Gas Notice of Inquiry soliciting comments on how to
introduce more competition into natural gas markets within Georgia. Following
written comments and oral presentations from numerous parties, on May 21, 1996,
the Georgia Commission adopted a Policy Statement that, among other things, sets
up a distinction between competitive and natural monopoly services; favors
performance-based regulation in lieu of traditional cost-of-service regulation;
calls for unbundling interruptible service; directs the Georgia Commission Staff
to develop standards of conduct for utilities and their marketing affiliates;
and invites pilot programs for unbundling services to residential and small
business customers.
Consistent with specific goals in the Georgia Commission's Policy
Statement, on June 10, 1996, AGLC filed a comprehensive plan for serving
interruptible markets called the Natural Gas Service Provider Selection Plan
(the Plan). The Plan proposes further unbundling of services to provide large
customers more service options and the ability to purchase only those services
they require. Proposed tariff changes would allow AGLC to cease its sales
service function and the associated sales obligation for large customers;
implement delivery-only service for large customers on a firm and interruptible
basis; and provide pooling services to marketers. The Plan also includes
proposed standards of conduct for utilities and marketing affiliates of
utilities. Hearings on the proposal began in December 1996 and are scheduled to
resume in January and February 1997. A decision is expected from the Georgia
Commission prior to March 1, 1997.
The second major initiative to increase competition and decrease the role
of regulation in Georgia is before study committees of the Georgia General
Assembly. The 1996 Georgia General Assembly considered, but delayed action on,
The Natural Gas Fair Pricing Act, which would have allowed local gas companies
to negotiate contract prices and terms for gas services with large commercial
and industrial customers absent Georgia Commission-mandated rates. The Georgia
General Assembly stated through resolutions a desire to fashion a more
comprehensive approach to deregulation and unbundling of natural gas services in
Georgia. Those resolutions, adopted during the 1996 session, created Senate and
House committees to study and recommend a comprehensive course of action by
December 31, 1996, for deregulating natural gas markets in Georgia.
The separate Senate and House study committees conducted joint meetings
during September, October and November 1996, with the goal of crafting a
comprehensive deregulation bill for the 1997 General Assembly, which convenes in
January 1997. The natural gas deregulation plan under consideration by the
committees would unbundle services to all of AGLC's natural gas customers, would
continue AGLC's role as the intrastate transporter of natural gas, would allow
AGLC to assign firm delivery capacity to certificated marketers who would sell
the gas commodity, and would create a secondary transportation market for
interruptible transportation capacity.
Although AGL Resources cannot predict the outcome of these two regulatory
reform initiatives, it supports both the plan under consideration by the Georgia
Commission and the plan under consideration by the Georgia General Assembly.
AGLC currently makes no profit on the purchase and sale of gas because actual
gas costs are passed through to customers under the purchased gas provisions of
AGLC's rate schedules. Earnings are provided through revenues received for
intrastate transportation of the commodity. Consequently, allowing AGLC to cease
its sales service function and the associated sales obligation would not
adversely affect AGLC's ability to earn a return on its distribution system
investment. In addition, allowing gas to be sold to all customers by numerous
marketers, including nonregulated subsidiaries of AGL Resources, would provide
new business opportunities.
GAS COST RECOVERY FILING
Pursuant to legislation enacted by the Georgia General Assembly, each
investor-owned local gas distribution company is required to file on or before
August 1 of each year, a proposed gas supply plan for the subsequent year, as
well as a proposed cost recovery factor to be used during the same time period.
Costs of natural gas supply, interstate transportation and storage incurred
pursuant to an approved plan may be recovered under the purchased gas provisions
of AGLC's rate schedules.
On August 1, 1996, AGLC filed its 1997 Gas Supply Plan, which consists of
gas supply, transportation and storage options designed to provide reliable
service to firm customers at the best cost. On September 13, 1996, the Georgia
Commission approved the entire supply portfolio contained in the 1997 Gas Supply
Plan.
As part of the 1997 Gas Supply Plan, AGLC is authorized to continue
limited gas supply hedging activities. The 1997 hedging program has been
expanded beyond the program approved in the 1996 Gas Supply Plan. The financial
results of all hedging activities are passed through to firm service customers
under the purchased gas provisions of AGLC's rate schedules. Accordingly, there
is no earnings impact as a result of the hedging program.
12
<PAGE>
Chattanooga Gas Company
RATE FILINGS
On May 1, 1995, Chattanooga filed a rate proceeding with the TRA seeking
an increase in revenues of $5.2 million annually. On September 27, 1995, a
settlement agreement was reached that provides for an annual increase in
revenues of approximately $2.5 million, effective November 1, 1995.
- --------------------------------------------------------------------------------
Item 2. Properties
AGL Resources considers its property and the property of its subsidiaries
to be well maintained, in good operating condition and suitable for their
intended purposes.
AGLC's properties consist primarily of distribution systems and related
facilities and local offices serving 235 cities and surrounding areas in the
State of Georgia and 12 cities and surrounding areas in the State of Tennessee.
As of September 30, 1996, AGLC had 25,642 miles of mains and 5,952,000 Mcf of
LNG storage capacity in three LNG plants to supplement the gas supply in very
cold weather or emergencies. Chattanooga had 1,328 miles of mains and 1,076,000
Mcf of LNG storage capacity in its one LNG plant. At September 30, 1996, AGLC's
gross utility plant amounted to approximately $2.0 billion.
AGL Resources' gross nonutility property amounted to approximately $81
million, consisting principally of assets related to Service Company.
- --------------------------------------------------------------------------------
Item 3. Legal Proceedings
The nature of the business of AGL Resources and its subsidiaries
ordinarily results in periodic regulatory proceedings before various state and
federal authorities and/or litigation incidental to the business. For
information regarding regulatory proceedings, see the preceding sections in Part
I, Item 1, "Business - Federal Regulatory Matters" and "Business - State
Regulatory Matters."
Arcadian
ARCADIAN CORPORATION V. SOUTHERN NATURAL GAS COMPANY AND ATLANTA GAS LIGHT
COMPANY, U. S. District Court for the Southern District of Georgia, Augusta
Division, Case No. CV192-006. On January 10, 1992, Arcadian, an industrial
customer of AGLC, filed a complaint against Southern and AGLC alleging violation
of the federal antitrust laws and seeking treble damages in excess of $45
million. In the complaint, Arcadian alleged that Southern and AGL conspired to
restrain trade by agreeing not to compete in the provision of direct
transportation service to end users in the areas served by AGLC. AGLC denied the
allegations of the complaint.
On November 30, 1993, a proposed settlement between Southern and Arcadian
was filed with FERC that would resolve both Arcadian's FERC complaint against
Southern and Arcadian's antitrust lawsuit against Southern and AGLC. The
settlement provided for firm and interruptible transportation service from
Southern to Arcadian at discounted rates for an initial term of five years. In
addition, the settlement establishes tariff conditions for addressing future
requests for direct transportation service. In connection with the proposed
settlement, the antitrust lawsuit has been stayed and administratively closed.
On May 12, 1994, FERC approved the settlement over AGLC's objections. AGLC has
sought rehearing of the FERC's order approving the settlement, and has
petitioned for review in the United States Court of Appeals for the Eleventh
Circuit. AGLC's appeals are currently being held in abeyance pending action by
the FERC on AGLC's rehearing request.
On April 22, 1996, AGLC filed to withdraw portions of its request for
rehearing of the FERC's order approving the November 12, 1993, settlement
between Arcadian and Southern. The arguments that AGLC proposes to withdraw,
pursuant to the restructuring settlement with Southern, are those that allege
that Southern's discounted rates to Arcadian constitute an anticompetitive
"price squeeze" against AGLC.
13
<PAGE>
Environmental Matters
AGLC has identified nine sites in Georgia where it currently owns all or
part of a manufactured gas plant (MGP) site. These sites are located in Athens,
Augusta, Brunswick, Griffin, Macon, Rome, Savannah, Valdosta and Waycross. In
addition, AGLC has identified three other sites in Georgia which AGLC does not
now own, but that may have been associated with the operation of MGPs by AGLC or
its predecessors. These sites are located in Atlanta (2) and Macon. A
Preliminary Assessment (PA) was conducted at each of those twelve sites, and a
subsequent Site Investigation (SI) was conducted at ten sites (all but the two
Atlanta sites). Results from those investigations reveal environmental impacts
at and near nine sites (all but the two Atlanta sites and the second Macon
site).
In addition, AGLC has identified three sites in Florida which may have
been associated with AGLC or its predecessors. One of these, located in Sanford,
Florida, is now the subject of an Expanded Site Investigation (ESI) which has
been or is being conducted by the U.S. Environmental Protection Agency (EPA).
Investigations at the site by AGLC and others have indicated environmental
impacts on and near the site. In addition, the current owner of this site,
Florida Public Utilities Company (FPUC), had previously filed suit against AGLC
and others alleging that AGLC is a former "owner" and seeking to obtain a
declaratory judgment that all defendants are jointly and severally liable for
past and future costs of investigating and remediating the site.
That suit has since been dismissed by FPUC without prejudice.
AGLC's response to MGP sites in Georgia is proceeding under two state
regulatory programs. First, AGLC has entered into consent orders with the
Georgia Environmental Protection Division (EPD) with respect to four sites:
Augusta, Griffin, Savannah, and Valdosta. Under these consent orders, AGLC is
obliged to investigate and, if necessary, remediate impacts at the site. AGLC
developed a proposed Corrective Action Plan (CAP) for the Griffin site, is now
conducting certain follow-up investigations in response to EPD's comments, and
expects to submit a revised CAP once EPD clarifies certain regulatory matters.
Assessment activities are being conducted at Augusta and Savannah. In addition,
AGLC is in the process of planning certain interim remedial measures at the
Augusta MGP site. Those measures are expected to be implemented principally
during fiscal 1997.
Second, AGLC's response to all Georgia sites is proceeding in substantial
compliance with Georgia's "Hazardous Site Response Act" (HSRA). AGLC submitted
to EPD formal notifications pertaining to all of its owned MGP sites, and EPD
had listed seven sites (Athens, Augusta, Brunswick, Griffin, Savannah, Valdosta
and Waycross) on the state's "Hazardous Site Inventory" (HSI). EPD has not
listed the Macon site on the HSI at this time. In addition, EPD has also listed
the Rome site on the HSI. Under the HSRA regulations, the four sites subject to
consent orders are presumed to require corrective action; EPD will determine
whether corrective action is required at the four remaining sites (Athens,
Brunswick, Rome and Waycross) in due course. In that respect, however, AGLC has
submitted Compliance Status Reports (CSRs) for the Athens, Brunswick and Rome
MGP sites, and AGLC has concluded that these sites do not meet applicable risk
reduction standards. Accordingly, some degree of response action is likely to be
required at those sites.
AGLC has estimated the investigation and remediation expenses likely to
be associated with the former MGP sites. First, since such liabilities are often
spread among potentially responsible parties, AGLC's ultimate liability will, in
some cases, be limited to AGLC's equitable share of such expenses under the
circumstances. Therefore, where reasonably possible, AGLC has attempted to
estimate the range of AGLC's equitable share, given AGLC's current knowledge of
relevant facts, including the current methods of equitable apportionment and the
solvency of potential contributors. Where such an estimation was not reasonably
possible, AGLC has estimated a range of expenses without adjustment for AGLC's
equitable share. Second, the regulatory structure of the cleanup requirements
under HSRA has permitted AGLC to estimate future investigation and remediation
costs for the Georgia MGP sites, assuming such costs arise under this framework.
Applying both of these concepts to those sites where some future action
presently appears reasonably possible, AGLC has estimated that, under the most
favorable circumstances reasonably possible, the future cost to AGLC of
investigating and remediating the former MGP sites could be as low as $30.4
million. Alternatively, AGLC has estimated that, under reasonably possible
unfavorable circumstances, the future cost to AGLC of investigating and
remediating the former MGP sites could be as high as $110.8 million. If
additional sites were added to those for which action now appears reasonably
likely, or if substantially more stringent cleanups were required, or if site
conditions are markedly worse than those now anticipated, the costs could be
higher. In addition, those costs do not include other expenses, such as property
damage claims, for which AGLC may
14
<PAGE>
ultimately be held liable, but for which neither the existence nor the amount of
such liabilities can be reasonably forecast. Within the stated range of $30.4
million to $110.8 million, no amount within the range can be reliably identified
as a better estimate than any other estimate. Therefore, a liability at the low
end of this range and a corresponding regulatory asset have been recorded in the
financial statements.
AGLC has two means of recovering the expenses associated with the former
MGP sites. First, the Georgia Commission has approved the recovery by AGLC of
Environmental Response Costs, as defined, pursuant to an Environmental Response
Cost Recovery Rider (ERCRR). For purposes of the ERCRR, Environmental Response
Costs include investigation, testing, remediation and litigation costs and
expenses or other liabilities relating to or arising from MGP sites. In
connection with the ERCRR, the staff of the Georgia Commission has undertaken a
financial and management process audit related to the MGP sites, cleanup
activities at the sites and environmental response costs that have been incurred
for purposes of the ERCRR. On October 10, 1996, the Georgia Commission issued an
order to prohibit funds collected through the ERCRR from being used for the
payment of any damage award, including punitive damages, as a result of any
litigation associated with any of the MGP sites in which AGLC is involved. AGLC
is currently pursuing judicial review of the October 10, 1996, order.
Second, AGLC intends to seek recovery of appropriate costs from its
insurers and other potentially responsible parties. With respect to its
insurers, in 1991, AGLC filed a declaratory judgment action against 23 of its
insurance companies. After the trial court entered a judgment adverse to AGLC
and AGLC appealed that ruling, the Eleventh Circuit Court of Appeals held that
the case did not present a case or controversy when filed, and the case was
remanded with instructions to dismiss. Since the Eleventh Circuit's decision,
AGLC has settled with, or is close to settlement with, most of the major
insurers. AGLC has not determined what actions it will take with respect to
non-settling insurers. During fiscal 1996 AGLC recovered $14.7 million from its
insurance carriers and other potentially responsible parties. In accordance with
provisions of the ERCRR, AGLC recognized other income of $2.9 million and
established regulatory liabilities for the remainder of those recoveries.
Other Legal Proceedings
With regard to other legal proceedings, AGL Resources is a party, as both
plaintiff and defendant, to a number of other suits, claims and counterclaims on
an ongoing basis. Management believes that the outcome of all litigation in
which it is involved will not have a material adverse effect on the consolidated
financial statements of AGL Resources.
- --------------------------------------------------------------------------------
Item 4. Submission of Matters to a Vote of Security Holdlers
No matters were submitted to a vote of security holders during the fourth
quarter of the fiscal year covered by this report.
- --------------------------------------------------------------------------------
15
<PAGE>
Item 4.(A) Executive Officers of the Registrant
Set forth below, in accordance with General Instruction G(3) of Form 10-K
and Instruction 3 of Item 401(b) of Regulation S-K, is certain information
regarding the executive officers of AGL Resources. Unless otherwise indicated,
the information set forth is as of September 30, 1996.
DAVID R. JONES, age 59, President and Chief Executive Officer of AGL
Resources (since January 1996), President and Chief Executive Officer and
director of Service Company (since August 1996), President and Chief Executive
officer of AGLC (since 1988) and director of AGLC (since 1985); director of the
Federal Reserve Bank of Atlanta. Mr. Jones has been a director of AGL Resources
since January 1996.
CHARLES W. BASS, age 49, Executive Vice President and Chief Operating
Officer of AGL Resources since August 1996, Executive Vice President Market
Service and Development of AGLC from 1994 until 1996 and Senior Vice President
Governmental and Regulatory Affairs of AGLC from 1988 until 1994 .
THOMAS H. BENSON, age 51, Executive Vice President of AGL Resources and
Chief Operating Officer of AGLC since August 1996, Executive Vice President
Customer Operations of AGLC from 1994 until 1996 and Senior Vice President
Operations and Engineering of AGLC from 1988 until 1994.
ROBERT L. GOOCHER, age 46, Executive Vice President of AGL Resources and
Chief Operating Officer of Service Company since August 1996, Executive Vice
President Business Support of AGLC from 1994 until 1996, Senior Vice President
and Chief Financial Officer of AGLC from 1992 until 1994, Vice President Finance
of AGLC from 1991 until 1992 and Vice President and Augusta Division manager of
AGLC from 1987 until 1991.
CHARLIE J. LAIL, age 57, Senior Vice President Operations Improvement of
AGLC since 1994, Senior Vice President Divisions of AGLC from 1992 until 1994,
Vice President Divisions of AGLC from 1991 until 1992 and Vice President and
Northeast Georgia Division manager of AGLC from 1988 until 1991.
RICHARD H. WOODWARD, Jr., age 49, Vice President of AGL Resources and
President of AGL Investments since August 1996, Senior Vice President Business
Development of AGLC from 1994 until 1996 and Senior Vice President Corporate
Services of AGLC from 1988 until 1994.
MICHAEL D. HUTCHINS, age 45, Vice President Operations and Engineering of
AGLC since 1994, Vice President Engineering of AGLC from 1989 until 1994.
CLAYTON H. PREBLE, age 49, Vice President of AGL Resources and President
of The Energy Spring, Inc., since August 1996, Vice President -- Marketing of
AGLC from 1994 until 1996, Vice President Corporate Planning of AGLC from 1994
until 1994, Director Corporate Planning of AGLC from 1992 until 1994 and
Northeast Georgia Division manager of AGLC from 1991 until 1992.
J. MICHAEL RILEY, age 45, Vice President and Chief Financial Officer of
AGL Resources since August 1996 and Chief Financial Officer of AGLC since
November 1996, Vice President Finance and Accounting of AGLC from 1994 until
1996, Vice President and Controller of AGLC from 1991 until 1994 and Controller
of AGLC from 1986 until 1991.
There are no family relationships among the executive officers.
All officers generally are elected annually by the Board of Directors at
the first meeting following the Annual Meeting of Shareholders in February.
16
<PAGE>
- --------------------------------------------------------------------------------
Part II
- --------------------------------------------------------------------------------
Item 5. Market for the Registrants' Common Equity and Related Stockholder
Matters
Information relating to the market for holders of and dividends on AGL
Resources' common stock is set forth under the caption "Shareholder Information"
on page 47 of AGL Resources' 1996 Annual Report. Such information is
incorporated herein by reference. Portions of the 1996 Annual Report are filed
as Exhibit 13 to this report.
- --------------------------------------------------------------------------------
Item 6. Selected Financial Data
Selected financial data for AGL Resources for each year of the five-year
period ended September 30, 1996 is set forth under the caption "Selected
Financial Data" on page 45 of AGL Resources' 1996 Annual Report referred to in
Item 5 above. Such five-year selected financial data is incorporated herein by
reference.
- --------------------------------------------------------------------------------
Item 7. Management's Discussion and Analysis of Results of Operations
and Financial Condition
A discussion of AGL Resources' results of operations and financial
condition is set forth under the caption "Management's Discussion and Analysis
of Results of Operations and Financial Condition" on pages 22 through 29 of AGL
Resources' 1996 Annual Report referred to in Item 5 above. Such discussion is
incorporated herein by reference.
- --------------------------------------------------------------------------------
Item 8. Financial Statements and Supplementary Data
The following financial statements of AGL Resources, which are set forth
on pages 30 through 44 of AGL Resources' 1996 Annual Report referred to in Item
5 above, are incorporated herein by reference:
Statements of Consolidated Income for the years ended September 30, 1996,
1995 and 1994.
Statements of Consolidated Cash Flows for the years ended September 30,
1996, 1995 and 1994.
Consolidated Balance Sheets as of September 30, 1996 and 1995.
Statements of Consolidated Common Stock Equity for the years ended
September 30, 1996, 1995 and 1994.
Notes to Consolidated Financial Statements.
Independent Auditors' Report.
The supplementary financial information required by Item 302 of Regulation
S-K is set forth in Note 14 in Notes to Consolidated Financial Statements in
AGL Resources' 1996 Annual Report to Shareholders.
The following supplemental data is submitted herewith:
Financial Statement Schedule - Valuation and Qualifying Account -
Allowance for Uncollectible Accounts.
Independent Auditors' Report.
- --------------------------------------------------------------------------------
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
None
17
<PAGE>
- --------------------------------------------------------------------------------
Part III
- --------------------------------------------------------------------------------
Item 10. Directors and Executive Officers of the Registrants
Information relating to nominees for director of AGL Resources is set
forth under the caption "Election of Directors-Information Concerning Nominees"
in the Proxy Statement for the 1996 Annual Meeting of Shareholders. Such
information is incorporated herein by reference. The definitive Proxy Statement
will be filed with the Securities and Exchange Commission within 120 days after
AGL Resources' fiscal year end. Information relating to the executive officers
of AGL Resources, pursuant to Instruction 3 of Item 401(b) of Regulation S-K and
General Instruction G(3) of Form 10-K, is set forth at Part I, Item 4(A) of this
report under the caption "Executive Officers of the Registrant."
- --------------------------------------------------------------------------------
Item 11. Executive Compensation
Information relating to executive compensation is set forth under the
caption "Executive Compensation" in the Proxy Statement referred to in Item 10
above. Such information is incorporated herein by reference.
- --------------------------------------------------------------------------------
Item 12. Security Ownership of Certain Beneficial Owners and Management
Information relating to ownership of common stock of AGL Resources by
certain persons is set forth under the caption "Security Ownership of
Management" in the Proxy Statement referred to in Item 10 above. Such
information is incorporated herein by reference.
- --------------------------------------------------------------------------------
Item 13. Certain Relationships and Related Transactions
Information relating to existing or proposed relationships or transactions
between AGL Resources and any affiliate of AGL Resources is set forth under the
caption "Compensation Committee Interlocks and Insider Participation" in the
Proxy Statement referred to in Item 10 above. Such information is incorporated
herein by reference.
The remainder of this page was intentionally left blank.
18
<PAGE>
- --------------------------------------------------------------------------------
Part IV
- --------------------------------------------------------------------------------
Item 14. Exhibits, Financial Statements Scheduled and Reports on Form 8-K
(a) Documents Filed as Part of This Report:
1. Financial Statements
Included under Item 8 are the following financial
statements:
Statements of Consolidated Income for the Years Ended
September 30, 1996, 1995 and 1994.
Statements of Consolidated Cash Flows for the Years Ended
September 30, 1996, 1995 and 1994.
Consolidated Balance Sheets as of September 30, 1996 and
1995.
Statements of Consolidated Common Stock Equity for the Years
Ended September 30, 1996, 1995 and 1994.
Notes to Consolidated Financial Statements.
Independent Auditors' Report.
2. Supplemental Consolidated Financial Schedules for Each of the
Three Years in the Period Ended September 30, 1996:
Independent Auditors' Report.
II. - Valuation and Qualifying Account--Allowance for
Uncollectible Accounts.
Schedules other than those referred to above are omitted and
are not applicable or not required, or the required
information is shown in the financial statements or notes
thereto.
3. Exhibits
Where an exhibit is filed by incorporation by reference to a
previously filed registration statement or report, such
registration statement or report is identified in parentheses.
3.1 - Amended and Restated Articles of Incorporation filed January 5,
1996, with the Secretary of State of the State of Georgia
(Exhibit B to the Proxy Statement and Prospectus filed as a part
of Amendment No. 1 to Registration Statement on Form S-4, No.
33-99826).
3.2 - Bylaws (Exhibit 3.2 to Registration Statement on Form S-4, No.
33-99826).
4.1 - Specimen form of Common Stock Certificate
19
<PAGE>
4.2 - Specimen form of Right Certificate (Exhibit 1 to Form 8-K filed
March 6, 1996).
10.1 - Executive Compensation Plans and Arrangements
10.1.a - Executive Severance Pay Plan of AGL Resources Inc.
10.1.b - AGL Resources Inc. Long-Term Stock Incentive Plan of 1990
(Exhibit 10(ii), Atlanta Gas Light Company Form 10-K for the
fiscal year ended September 30, 1991).
10.1.c - First Amendment to the AGL Resources Inc. Long-Term
Stock Incentive Plan of 1990 (Exhibit B to the Atlanta Gas Light
Company Proxy Statement for the Annual Meeting of Shareholders
held February 5, 1993).
10.1.d - Third Amendment to the AGL Resources Inc. Long-Term
Stock Incentive Plan of 1990 (Exhibit C to the Proxy Statement
and Prospectus filed as a part of Amendment No. 1 to
Registration Statement on Form S-4, No. 33-99826).
10.1.e - AGL Resources Inc. Nonqualified Savings Plan (Exhibit 10(a),
Atlanta Gas Light Company Form 10-K for the fiscal year ended
September 30, 1995).
10.1.f - AGL Resources Inc. Non-Employee Directors Equity Compensation
Plan (Exhibit B to the Proxy Statement and Prospectus filed as a
part of Amendment No. 1 to Registration Statement on Form S-4,
No. 33-99826).
13 - Portions of the AGL Resources Inc. 1996 Annual Report to
Shareholders.
21 - Subsidiaries of AGL Resources Inc.
23 - Independent Auditors' Consent.
24 - Powers of Attorney (included with Signature Page hereto).
27 - Financial Data Schedule.
(b) Reports on Form 8-K
No Form 8-K was filed during the last quarter of the year ended September
30, 1996.
The remainder of this page was intentionally left blank.
20
<PAGE>
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized, on November 1, 1996.
AGL RESOURCES INC.
By: /s/ David R. Jones
David R. Jones
President and Chief Executive Officer
POWERS OF ATTORNEY
KNOW ALL MEN BY THESE PRESENTS, that each person whose signature
appears below constitutes and appoints David R. Jones and J. Michael Riley, and
each of them, his or her true and lawful attorneys-in-fact and agents, with full
power of substitution and resubstitution, for him or her and in his or her name,
place and stead, in any and all capacities, to sign the Annual Report on Form
10-K for the fiscal year ended September 30, 1996 and any and all amendments to
such Annual Report, and to file the same, with all exhibits thereto and other
documents in connection therewith, with the Securities and Exchange Commission,
granting unto said attorneys-in-fact and agents, and each of them, full power
and authority to do and perform each and every act and thing requisite or
necessary to be done, as fully to all intents and purposes as he or she might or
could do in person, hereby ratifying and confirming all that said
attorneys-in-fact and agents or any of them, or their or his substitute or
substitutes, may lawfully do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
Registrant and in the capacities indicated as of November 1, 1996.
Signatures Title
/s/ David R. Jones
David R. Jones President and Chief Executive Officer
(Principal Executive Officer) and Director
/s/ J. Michael Riley
J. Michael Riley Vice President and Chief Financial Officer
(Principal Accounting and Financial Officer)
/s/ Frank Barron, Jr.
Frank Barron, Jr. Director
21
<PAGE>
/s/ W. Waldo Bradley
W. Waldo Bradley Director
/s/ Otis A. Brumby, Jr.
Otis A. Brumby, Jr. Director
/s/ L.L. Gellerstedt, III
L.L. Gellerstedt, III Director
/s/ Albert G. Norman, Jr.
Albert G. Norman, Jr. Director
/s/ D. Raymond Riddle
D. Raymond Riddle Director
/s/ Betty L. Siegel
Betty L. Siegel Director
/s/ Ben J. Tarbutton, Jr.
Ben J. Tarbutton, Jr. Director
/s/ Charles McKenzie Taylor
Charles McKenzie Taylor Director
/s/ Felker W. Ward, Jr.
Felker W. Ward, Jr. Director
*By /s/ J. Michael Riley
J. Michael Riley
as Attorney-in-Fact
22
<PAGE>
INDEPENDENT AUDITORS' REPORT
To the Shareholders and Board of Directors of AGL Resources Inc.:
We have audited the consolidated balance sheets of AGL Resources Inc. and its
subsidiaries as of September 30, 1996 and 1995, and the related statements of
consolidated income, common stock equity, and cash flows for each of the three
years in the period ended September 30, 1996, and have issued our report thereon
dated November 5, 1996; such financial statements and report are included in
your 1996 Annual Report to Shareholders and are incorporated herein by
reference. Our audits also included the financial statement schedule of AGL
Resources Inc. and subsidiaries, listed in Item 14. This financial statement
schedule is the responsibility of AGL Resources Inc.'s management. Our
responsibility is to express an opinion based on our audits. In our opinion,
such financial statement schedule, when considered in relation to the basic
financial statements taken as a whole, presents fairly in all material respects
the information set forth therein.
/S/ DELOITTE & TOUCHE LLP
DELOITTE & TOUCHE LLP
Atlanta, Georgia
November 5, 1996
23
<PAGE>
SCHEDULE II
AGL RESOURCES INC. AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNT
ALLOWANCE FOR UNCOLLECTIBLE ACCOUNTS
FOR THE YEARS ENDED SEPTEMBER 30, 1996, 1995 AND 1994
(IN MILLIONS)
- --------------------------------------------------------------------------------
1996 1995 1994
- --------------------------------------------------------------------------------
Balance, beginning of year ................. 4.4 2.8 1.9
Additions:
Provisions charged to income ............. 4.7 5.3 7.5
Recovery of accounts
previously written off
as uncollectible ....................... 8.6 6.6 7.1
------ ------ ------
Total ................................ 17.7 14.7 16.5
Deduction:
Accounts written off
as uncollectible ....................... 14.9 10.3 13.7
------ ------ ------
Balance, end of year ....................... 2.8 4.4 2.8
====== ====== ======
24
<PAGE>
Exhibit 13
MANAGEMENTS DISCUSSION OF RESULTS OF OPERATIONS AND FINANCIAL CONDITION
(GRAPH APPEARS HERE)
(GRAPH APPEARS HERE)
On March 6, 1996, AGL Resources Inc. (AGL Resources) became the holding company
for Atlanta Gas Light Company (AGLC), a natural gas distribution utility; AGLC's
wholly owned natural gas utility subsidiary, Chattanooga Gas Company
(Chattanooga); and AGLC's nonregulated subsidiaries: AGL Energy Services, Inc.;
AGL Investments, Inc.; Georgia Gas Company; Georgia Gas Service Company; Georgia
Energy Company; and Trustees Investments, Inc. During fiscal 1996 ownership of
AGLC's nonregulated businesses was transferred to AGL Resources and its various
subsidiaries. (See Note 1 in Notes to Consolidated Financial Statements.) Unless
noted specifically or otherwise required by the context, references to AGLC or
the utility include the operations and activities of AGLC and Chattanooga.
The following discussion and analysis reflects the results of operations
and financial condition of AGL Resources for the three years ended September 30,
1996, and factors expected to impact its future operations.
RESULTS OF OPERATIONS
Fiscal 1996 Compared with Fiscal 1995
Operating Revenues
Operating revenues increased 14.8% in 1996 compared with 1995 primarily due to
(1) an increase in the cost of the gas supply recovered from customers under the
purchased gas provisions of the utility's rate schedules, (2) increased volumes
of gas sold to firm service customers as a result of weather that was 50% colder
in 1996 than in 1995 and (3) an increase of approximately 41,000 in the number
of customers served.
Cost of Gas
Cost of gas increased 26% in 1996 compared with 1995 primarily due to (1) an
increase in the cost of the gas supply recovered from customers under the
purchased gas provisions of the utility's rate schedules and (2) increased
volumes of gas sold to firm service customers as a result of weather that was
50% colder in 1996 than in 1995.
The utility's cost of natural gas per therm was 32.2 cents in 1996 and 29.7
cents in 1995. Variations in the cost of purchased gas are passed through to
customers under the purchased gas provisions of the utility's rate schedules.
Overrecoveries or underrecoveries of purchased gas costs are charged or credited
to cost of gas and are included in current assets or liabilities, thereby
eliminating the effect that recovery of gas costs otherwise would have on net
income.
Operating Margin
Operating margin increased 1.8% in 1996 compared with 1995 primarily due to (1)
recovery of increased expenses related to an Integrated Resource Plan (IRP),
which are recovered through an IRP Cost Recovery Rider approved by the Georgia
Public Service Commission (Georgia Commission), (2) a revenue increase granted
by the Tennessee
<PAGE>
Regulatory Authority (TRA), formerly the Tennessee Public
Service Commission, effective November 1, 1995, and (3) an increase of
approximately 41,000 in the number of customers served.
Restructuring Costs
In November 1994 AGL Resources announced a corporate restructuring plan in
response to increased competition and changes in the federal and state
regulatory environments in which AGLC operates. Restructuring costs of $61.4
million related to early retirement and severance programs and $8.9 million
related to office closings and costs to exit AGLC's appliance merchandising and
real estate investment operations were recorded during 1995. There were no
restructuring costs recorded in 1996.
During the fourth quarter of fiscal 1996, AGL Resources reviewed its remaining
liabilities with respect to its corporate restructuring plan. As a result, AGL
Resources adjusted its restructuring accruals and reduced operating expenses by
$2.7 million, before income taxes. The remaining balance of restructuring
liabilities as of September 30, 1996, and 1995, was $1 million and $4.8 million,
respectively.
Other Operating Expenses
Operation and maintenance expenses increased 2.6% in 1996 compared with 1995
primarily due to (1) an increase of $3.6 million in expenses related to an
Integrated Resource Plan (IRP) and (2) an increase of $1.2 million in franchise
expenses. IRP and franchise expenses are recovered from customers through rate
recovery riders approved by the Georgia Commission. As a result, IRP program
costs and franchise expenses do not affect net income. Operation and maintenance
expenses excluding IRP and franchise expenses increased slightly primarily due
to (1) increased uncollectible accounts expenses and (2) expenses associated
with the formation of AGL Resources. The increase in operation and maintenance
expenses excluding IRP and franchise expenses was offset partly by decreased
labor-related expenses.
Depreciation expense increased 6.8% in 1996 compared with 1995 primarily due to
increased depreciable plant in service. The composite straight-line depreciation
rate was approximately 3.2% for utility property other than transportation
equipment during 1996 and 1995.
Taxes other than income taxes decreased $0.7 million primarily due to decreased
ad valorem taxes.
Other Income
Other income increased $12.2 million in 1996 compared with 1995 primarily due to
(1) income in 1996 from a gas marketing joint venture, (2) income from carrying
costs on increased deferred purchased gas undercollections and (3) recoveries of
environmental response costs from insurance carriers and third parties.
Interest Expense
Total interest expense increased $1.6 million in 1996 compared with 1995
primarily due to increased amounts of short-term debt outstanding. The increase
was offset partly by decreased amounts of long-term debt outstanding.
Income Taxes
Income taxes increased $30.8 million in 1996 compared with 1995 primarily due to
increased taxable income.
Net Income and Dividends
On November 3, 1995, the Board of Directors declared a two-for-one stock split
of the common stock effected in the form of a 100% stock dividend to
shareholders of record on November 17, 1995, and paid on December 1, 1995. All
references to number of shares and to per share amounts have been restated
retroactively to reflect the stock split.
Net income for 1996 was $75.6 million, compared with $26.4 million in 1995.
Earnings per share of common stock were $1.37 in 1996, compared with $0.50 in
1995. Dividends per share of common stock were $1.06 in 1996, compared with
$1.04 in 1995. The increases in net income and earnings per share were primarily
due to (1) corporate restructuring costs of $43.1 million, after income taxes,
recorded in 1995, (2) increased other income and (3) increased operating margin
as a result of an increase of approximately 41,000 in the number of customers
served. The increases in net income and earnings per share were offset partly by
increased depreciation expense. The increase in earnings per share also was
offset partly by an increase in the number of common shares outstanding.
Fiscal 1995 Compared with Fiscal 1994
Operating Revenues
Operating revenues decreased 11.4% in 1995 compared with 1994 primarily due to
(1) a decrease in the cost of the gas supply recovered from customers under the
purchased gas provisions of the utility's rate schedules and (2) decreased
volumes of gas sold to firm service customers as a result of weather that was
17% warmer in 1995 than in 1994. The decrease in operating revenues was offset
partly by an increase of approximately 37,000 in the number of customers served.
<PAGE>
Cost of Gas
Cost of gas decreased 22.4% in 1995 compared with 1994 primarily due to (1) a
decrease in the cost of the gas supply recovered from customers under the
purchased gas provisions of the utility's rate schedules and (2) decreased
volumes of gas sold to firm service customers as a result of weather that was
17% warmer in 1995 than in 1994.
The utility's cost of natural gas per therm was 29.7 cents in 1995 and 37.7
cents in 1994. Variations in the cost of purchased gas are passed through to
customers under the purchased gas adjustment provisions of the utility's rate
schedules.
Operating Margin
Operating margin increased 6.1% in 1995 compared with 1994
primarily due to an increase of approximately 37,000 in the number of customers
served.
Restructuring Costs
In November 1994 AGL Resources announced a corporate restructuring plan in
response to increased competition and changes in the federal and state
regulatory environments in which AGLC operates.
The restructuring plan provided for reengineering AGLC's business processes and
streamlining AGLC's statewide field organizations. As a result of restructuring,
AGLC combined offices and established centralized customer service centers.
During 1995, AGLC reduced the average number of employees by approximately 500
through voluntary retirement and severance programs, and attrition.
Restructuring costs of $61.4 million related to early retirement and severance
programs and $8.9 million related to office closings and costs to exit AGLC's
appliance merchandising and real estate investment operations were recorded
during 1995.
Other Operating Expenses
Operation and maintenance expenses increased 1.7% in 1995 compared with 1994
primarily due to an increase of $17 million in expenses related to an IRP, which
are recovered through an IRP Cost Recovery Rider approved by the Georgia
Commission. As a result, IRP program costs do not affect net income. Operation
and maintenance expenses excluding IRP expenses decreased 5.4% in 1995 compared
with 1994 primarily due to (1) decreased labor costs as a result of the
restructuring plan, (2) decreased uncollectible accounts expenses and (3)
decreased regulatory commission expenses.
Depreciation expense increased 5.6% in 1995 compared with 1994 primarily due to
increased depreciable plant in service. The composite straight-line depreciation
rate was approximately 3.2% for utility property other than transportation
equipment during 1995 and 1994.
Taxes other than income taxes decreased $0.4 million primarily due to decreased
payroll taxes as a result of AGL Resources' restructuring plan. The decrease in
taxes other than income taxes was offset partly by increased ad valorem taxes.
Other Income
Other income decreased $3.1 million in 1995 compared with 1994 primarily due to
(1) decreased income from propane operations as a result of warmer weather and
(2) decreased income from merchandise operations.
Interest Expense
Total interest expense decreased $0.1 million in 1995 compared with 1994
primarily due to increased allowance for funds used during construction -- debt.
Interest on long-term debt decreased $0.5 million in 1995 compared with 1994 due
to decreased amounts of long-term debt outstanding. The decreased interest
expense on long-term debt was offset by a $0.4 million increase in other
interest expenses primarily due to increased interest rates on short-term debt.
Income Taxes
Income taxes decreased $19.6 million in 1995 compared with 1994 primarily
due to decreased taxable income.
Net Income and Dividends
Net income for 1995 was $26.4 million, compared with $58.7 million for 1994.
Earnings per share of common stock were $0.50 in 1995, compared with $1.17 in
1994. Dividends per share of common stock were $1.04 for 1995 and 1994. The
decreases in net income and earnings per share were primarily due to the cost of
the restructuring plan. The decreases in net income and earnings per share were
offset partly by (1) increased operating margin as a result of an increase of
approximately 37,000 in the number of customers served and (2) decreased other
operating expenses as a result of the restructuring plan. Excluding charges
recorded during 1995
<PAGE>
related to the restructuring plan, net income and earnings per share would have
been approximately $69.5 million and $1.32, respectively.
Impact of Inflation
Inflation impacts the prices AGL Resources must pay for labor and other goods
and services required for operation, maintenance and capital improvements. The
utility's rate schedules include purchased gas adjustment provisions that permit
the increases in gas costs to be passed on to its customers. Increases in costs
not recovered through the purchased gas adjustment provisions and other similar
rate riders must be recovered through timely filings for rate relief.
FINANCIAL CONDITION
Financing
Common Stock
On June 16, 1995, approximately 3 million shares of common stock were issued and
sold at $16.81 per share, resulting in net proceeds of $48.6 million. Proceeds
from that sale of common stock were used to finance capital expenditures and for
other corporate purposes. AGL Resources issued 762,553; 1,092,486; and 1,144,270
shares of common stock during fiscal 1996, 1995 and 1994, respectively, for its
Dividend Reinvestment and Stock Purchase Plan, Retirement Savings Plus Plan,
Long-Term Stock Incentive Plan, Nonqualified Savings Plan and the Non-Employee
Directors Equity Compensation Plan, which increased common equity by
approximately $14 million, $18 million and $20 million, respectively.
Long-Term Debt
During fiscal 1994, $194.5 million in principal amount of medium-term notes,
Series C, was issued, with maturity dates ranging from 10 to 30 years and with
interest rates ranging from 5.9% to 7.2%. The notes are issued under an
Indenture dated December 1, 1989, and are unsecured and rank on a parity with
all other unsecured indebtedness. Net proceeds from the notes were used to repay
short-term debt, to refund $125 million in principal amount of First Mortgage
Bonds and for other corporate purposes. Approximately $105 million in principal
amount of medium-term notes, Series C, was unissued as of September 30, 1996,
and 1995.
Short-Term Debt
Because AGL Resources' primary business is highly seasonal, short-term debt is
used to meet seasonal working capital requirements. In addition, capital
expenditures are funded temporarily with short-term debt. Lines of credit with
various banks provide for direct borrowings and are subject to annual renewal.
The current lines of credit vary from $75 million in the summer months to $253
million for peak winter financing. Short-term debt increased $101 million from
the amount outstanding as of September 30, 1995, to $152 million as of September
30, 1996, primarily as a result of the increased use of short-term debt to
temporarily fund capital expenditures. For additional information concerning
short-term debt, see Note 8 in Notes to Consolidated Financial Statements.
Capital Requirements
Capital expenditures for construction of distribution facilities, purchase of
equipment and other general improvements were $132.5 million during 1996.
Capital requirements are estimated to be approximately $350 million for the
three years ending September 30, 1999. During the same period, approximately
$1.2 million will be required to fund preferred stock purchase fund obligations.
Funding for those expenditures will be provided through a combination of
internal sources and the issuance of short-term and long-term debt and equity
securities.
The cost of natural gas stored underground increased $32.8 million to $144
million as of September 30, 1996, primarily due to an increase in the cost of
the gas that was injected into storage.
Ratios and Coverages
On September 30, 1996, AGL Resources' capitalization ratios consisted of 46.1%
long-term debt, 4.9% preferred stock and 49.0% common equity. The times interest
earned and ratio of earnings to fixed charges increased in 1996 compared with
1995 primarily due to increased earnings. The times interest earned and ratio of
earnings to fixed charges decreased in 1995 compared with 1994 primarily due to
decreased earnings.
The weighted average cost of long-term debt decreased from 7.7% on September 30,
1994, to 7.6% on September 30, 1996. The decrease was due to the redemption of
$15 million in principal amount of 8.85% medium-term notes. The weighted average
cost of preferred stock was 7.5% on September 30, 1994, 1995 and 1996. The
return on average common equity was 11.6% for 1994; 4.9% for 1995; and 13.2% for
1996. Net income in 1995 included a charge for restructuring of $43.1 million,
after income taxes.
<PAGE>
Regulatory Activity
Order 636
In 1992 the Federal Energy Regulatory Commission (FERC) issued Order 636, which,
among other things, mandated the unbundling of interstate pipeline sales service
and established certain open access transportation regulations that became
effective beginning in the 1993-1994 heating season.
In Order 636 FERC acknowledged that, without special recovery mechanisms,
certain costs that previously were recovered in the pipelines' rate for bundled
sales services no longer could be recovered by the pipelines in a restructured
environment. Those costs, referred to as transition costs, include such things
as unrecovered gas costs, gas supply realignment (GSR) costs and various
stranded costs resulting from unbundling. Accordingly, Order 636 included a
recovery mechanism that allows the pipeline companies to pass through to their
customers any prudently incurred transition costs attributable to compliance
with Order 636.
On July 16, 1996, the United States Court of Appeals for the District of
Columbia Circuit issued its ruling in United Distribution Cos. v. FERC,
concerning appeals from Order 636. The court generally upheld FERC's orders
against a broad array of challenges, but remanded the orders to FERC for
reconsideration of certain issues, including FERC's decision to permit pipelines
to pass all of their GSR costs through to their customers and its decision to
require interruptible transportation customers to bear 10% of GSR costs. FERC
has not yet issued an order on remand, and thus it is not known whether FERC
will change its GSR policies. The court's order is subject to further
proceedings before the District of Columbia Circuit, and possibly the United
States Supreme Court.
AGLC, based on filings with FERC by its pipeline suppliers, estimates that its
portion of such costs from all of its pipeline suppliers would be approximately
$109.9 million. Such filings currently are pending before FERC for final
approval, and the transition costs are being collected subject to refund.
Approximately $80.6 million of such costs have been incurred by AGLC as of
September 30, 1996, recovery of which is provided under the purchased gas
provisions of AGLC's rate schedules.
Transition costs have not affected the total cost of gas to the utility's
customers significantly because (1) purchases of wellhead gas supplies are based
on market prices that are below the cost of gas previously embedded in the
bundled pipeline sales service rates and (2) many elements of transition costs
previously were embedded in the rates for the pipelines' bundled sales service.
Regulatory Reform Initiatives
Two regulatory reform initiatives are pending in Georgia, both designed to
increase competition and reduce the role of regulation within the natural gas
industry. The first such initiative is the subject of a proceeding before the
Georgia Commission; the second initiative is before study committees of the
Georgia General Assembly.
With respect to the first initiative, on November 20, 1995, the Georgia
Commission issued a Natural Gas Notice of Inquiry soliciting comments on how to
introduce more competition into natural gas markets within Georgia. Following
written comments and oral presentations from numerous parties, on May 21, 1996,
the Georgia Commission adopted a Policy Statement that, among other things, sets
up a distinction between competitive and natural monopoly services; favors
performance-based regulation in lieu of traditional cost-of-service regulation;
calls for unbundling interruptible service; directs the Georgia Commission Staff
to develop standards of conduct for utilities and their marketing affiliates;
and invites pilot programs for unbundling services to residential and small
business customers.
Consistent with specific goals in the Georgia Commission's Policy Statement, on
June 10, 1996, AGLC filed a comprehensive plan for serving interruptible markets
called the Natural Gas Service Provider Selection Plan (the Plan). The Plan
proposes further unbundling of services to provide large customers more service
options and the ability to purchase only those services they require. Proposed
tariff changes would allow AGLC to cease its sales service function and the
associated sales obligation; implement delivery-only service for large customers
on a firm and interruptible basis; and provide pooling services to marketers.
The Plan also includes proposed standards of conduct for utilities and marketing
affiliates of utilities. Hearings on the proposal have been scheduled for
December 1996 and January and February 1997. A decision is expected from the
Georgia Commission prior to March 1, 1997.
The second major initiative to increase competition and decrease the role of
regulation in Georgia is before study committees of the Georgia General
Assembly. The 1996 Georgia General Assembly considered, but delayed
<PAGE>
action on, The Natural Gas Fair Pricing Act, which would have allowed local gas
companies to negotiate contract prices and terms for gas services with large
commercial and industrial customers absent Georgia Commission-mandated rates.
The Georgia General Assembly stated through resolutions a desire to fashion a
more comprehensive approach to deregulation and unbundling of natural gas
services in Georgia. Those resolutions, adopted during the 1996 session, created
Senate and House committees to study and recommend a comprehensive course of
action by December 31, 1996, for deregulating natural gas markets in Georgia.
The separate Senate and House study committees conducted meetings during
September, October and November 1996, with the goal of crafting a comprehensive
deregulation bill for the 1997 General Assembly, which convenes in January 1997.
The natural gas deregulation plan under consideration by the committees would
unbundle services to all of AGLC's natural gas customers, would continue AGLC's
role as the intrastate transporter of natural gas, would allow AGLC to assign
firm delivery capacity to certificated marketers who would sell the gas
commodity, and would create a secondary transportation market for interruptible
transportation capacity.
Although AGL Resources cannot predict the outcome of those two regulatory reform
initiatives, it supports both the plan under consideration by the Georgia
Commission and the plan under consideration by the Georgia General Assembly.
AGLC currently makes no profit on the purchase and sale of gas because actual
gas costs are passed through to customers under the purchased gas provisions of
AGLC's rate schedules. Earnings are provided through revenues received for
intrastate transportation of the commodity. Consequently, allowing AGLC to cease
its sales service function and the associated sales obligation would not
adversely affect AGLC's ability to earn a return on its distribution system
investment. In addition, allowing gas to be sold to all customers by numerous
marketers, including nonregulated subsidiaries of AGL Resources, would provide
new earnings opportunities.
Gas Cost Recovery Filing
Pursuant to legislation enacted by the Georgia General Assembly, each
investor-owned local gas distribution company is required to file on or before
August 1 of each year, a proposed gas supply plan for the subsequent year, as
well as a proposed cost recovery factor to be used during the same time period.
Costs of natural gas supply, interstate transportation and storage incurred
pursuant to an approved plan may be recovered under the purchased gas provisions
of the utility's rate schedules.
On August 1, 1996, AGLC filed its 1997 Gas Supply Plan, which consists of gas
supply, transportation and storage options designed to provide reliable service
to firm customers at the best cost. On September 13, 1996, the Georgia
Commission approved the entire supply portfolio contained in the 1997 Gas Supply
Plan.
As part of the 1997 Gas Supply Plan, AGLC is authorized to continue limited gas
supply hedging activities. The 1997 hedging program has been expanded beyond the
program approved in the 1996 Gas Supply Plan. The financial results of all
hedging activities are passed through to firm service customers under the
purchased gas provisions of the utility's rate schedules. Accordingly, there is
no earnings impact as a result of the hedging program.
Rate Filings
On May 1, 1995, Chattanooga filed a rate proceeding with the TRA seeking an
increase in revenues of $5.2 million annually. On September 27, 1995, a
settlement agreement was reached that provides for an annual increase in
revenues of approximately $2.5 million, effective November 1, 1995.
<TABLE>
<CAPTION>
1997 Gas Supply Plan
10 therms = 1 dekatherm Production
Firm Area Supplemental Total
Transportation Wellhead Underground Underground Liquefied Peak-Day
Capacity Gas Supply Storage Storage Natural Gas Supply
Atlanta Gas Light Company (dekatherms) (dekatherms) (dekatherms) (dekatherms) (dekatherms) (dekatherms)
<S> <C> <C> <C> <C> <C> <C>
Southern ................. 778,037 414,753 168,500
Transco .................. 137,989 103,356 280,241
Tennessee / East Tennessee 63,860 32,864
Southern / South Georgia . 12,115 6,906 708
Total .................... 992,001 520,655 557,879 449,449 665,000 2,106,450
Chattanooga Gas Company
East Tennessee ........ 46,350 23,857
Southern .............. 22,462 14,346
Total ................. 68,812 34,696 38,203 0 90,000 158,812
</TABLE>
<PAGE>
On August 3, 1993, Chattanooga made a rate filing with the TRA seeking an
increase in revenues of $5.7 million annually. On December 31, 1993, a
settlement agreement was reached that provided for an annual rate increase of
$3.5 million, effective February 1, 1994.
Weather Normalization
The Georgia Commission and the TRA have authorized weather normalization
adjustment riders (WNARs), which are designed to offset the impact that
unusually cold or warm weather has on customer billings and operating margin.
Because fiscal 1996 was colder than normal, the WNARs reduced net income and net
cash flow from operating activities to normal levels. Fiscal 1995 and 1994 were
warmer than normal, and the WNARs, therefore, increased net income and net cash
flow from operating activities to normal levels for those periods. The WNARs
decreased net income by $4.4 million in 1996, and increased net income by $27.3
million in 1995 and $12.6 million in 1994.
Environmental Matters
AGLC has identified nine sites in Georgia where it currently owns all or part of
a manufactured gas plant (MGP) site. In addition, AGLC has identified three
other sites in Georgia that AGLC does not now own, but that may have been
associated with the operation of MGPs by AGLC or its predecessors. There are
three sites in Florida that have been investigated by environmental authorities
in connection with which AGLC may be contacted as a potentially responsible
party. Preliminary assessments and subsequent site investigations have revealed
environmental impacts at and near some of those sites.
Under a thorough analysis of potentially applicable requirements, AGLC has
estimated that, under the most favorable circumstances reasonably possible, the
future cost of investigating and remediating the former MGP sites, excluding
sites for which no remediation is expected or the cost of which cannot be
estimated, could be as low as $30.4 million. Alternatively, AGLC has estimated
that, under the least favorable circumstances reasonably possible, the future
cost of investigating and remediating the same former MGP sites could be as high
as $110.8 million, excluding sites for which no remediation is expected or the
cost of which cannot be estimated. AGLC cannot estimate at this time the amount
of any other future expenses or liabilities, or the impact on those estimates of
future environmental or regulatory changes, that may be associated with or
related to the MGP sites, including expenses or liabilities relating to any
litigation. At the present time, no amount within the $30.4 million to $110.8
million range can be identified as a better estimate than any other estimate.
Therefore, a liability at the low end of this range and a corresponding
regulatory asset have been recorded in the financial statements.
The Georgia Commission has approved the recovery by AGLC of environmental
response costs, pursuant to AGLC's Environmental Response Cost Recovery Rider
(ERCRR). For purposes of the ERCRR, environmental response costs include
investigation, testing, remediation and litigation costs and expenses or other
liabilities relating to or arising from MGP sites. In connection with the ERCRR,
the staff of the Georgia Commission has undertaken a financial and management
process audit related to the MGP sites, cleanup activities at the sites and
environmental response costs that have been incurred for purposes of the ERCRR.
On October 10, 1996, the Georgia Commission issued an order to prohibit funds
collected through the ERCRR from being used for the payment of any damage award,
including punitive damages, as a result of any litigation associated with any of
the MGP sites in which AGLC is involved. AGLC is currently pursuing judicial
review of the October 10, 1996, order.
AGLC is currently a party to claims and litigation related to the former MGP
sites. During fiscal 1996 AGLC recovered $14.7 million from its insurance
carriers and other potentially responsible parties. In accordance with
provisions of the ERCRR, AGLC recognized other income of $2.9 million and
established regulatory liabilities for the remainder of those recoveries. AGLC
intends to continue to pursue insurance coverage and contributions from
potentially responsible parties.
Competition
AGLC competes to supply natural gas to interruptible customers who are capable
of switching to alternative fuels, including propane, fuel and waste oils,
electricity and, in some cases, combustible wood by-products. AGLC also competes
to supply gas to interruptible customers who might seek to bypass its
distribution system.
<PAGE>
AGLC can price distribution services to interruptible customers four ways.
First, multiple rates are established under the rate schedules of AGLC's tariff
approved by the Georgia Commission. If an existing tariff rate does not produce
a price competitive with a customer's relevant competitive alternative, three
alternate pricing mechanisms exist: Negotiated Contracts, Interruptible
Transportation and Sales Maintenance (ITSM) discounts, and Special Contracts.
On February 17, 1995, the Georgia Commission approved a settlement that permits
AGLC to negotiate contracts with customers who have the option of bypassing
AGLC's facilities (Bypass Customers) to receive natural gas from other
suppliers. The bypass avoidance contracts (Negotiated Contracts) can be
renewable, provided the initial term does not exceed five years, unless a longer
term specifically is authorized by the Georgia Commission. The rate provided by
the Negotiated Contract may be lower than AGLC's filed rate, but not less than
AGLC's marginal cost of service to the potential Bypass Customer. Service
pursuant to a Negotiated Contract may commence without Georgia Commission
action, after a copy of the contract is filed with the Georgia Commission.
Negotiated Contracts may be rejected by the Georgia Commission within 90 days of
filing; absent such action, however, the Negotiated Contracts remain in effect.
None of the Negotiated Contracts filed to date with the Georgia Commission have
been rejected.
The settlement also provides for a bypass loss recovery mechanism to operate
until the earlier of September 30, 1998, or the effective date of new rates for
AGLC resulting from a general rate case.
In addition to Negotiated Contracts, which are designed to serve existing and
potential Bypass Customers, AGLC's ITSM Rider continues to permit discounts for
short-term transactions to compete with alternative fuels. Revenue shortfalls,
if any, from interruptible customers as measured by the test-year interruptible
revenues determined by the Georgia Commission in AGLC's 1993 rate case will
continue to be recovered under the ITSM Rider.
The settlement approved by the Georgia Commission also provides that AGLC may
file contracts (Special Contracts) for Georgia Commission approval if the
service cannot be provided through the ITSM Rider, existing rate schedules, or
Negotiated Contract procedures. A Special Contract, for example, could involve
AGLC providing a long-term service contract to compete with alternative fuels
where physical bypass is not the relevant competition.
Pursuant to the approved settlement, AGLC has filed and is providing service
pursuant to 46 Negotiated Contracts. Additionally, the Georgia Commission has
approved Special Contracts between AGLC and five interruptible customers.
On July 22, 1996, Chattanooga filed a plan with the TRA that, if approved, would
permit Chattanooga to negotiate contracts with customers in Tennessee who have
long-term competitive options, including bypass. On November 7, 1996, the TRA
hearing officer recommended approval of a settlement that permits Chattanooga to
negotiate contracts with large commercial or industrial customers who are
capable of bypassing Chattanooga's distribution system. The settlement provides
for approval on an experimental basis, with the TRA to review the measure two
years from the approval date. The pricing terms provided in any such contract
may be neither less than Chattanooga's marginal cost of providing service nor
greater than the filed tariff rate generally applicable to such service.
Chattanooga can recover 50% of the difference between the contract rate and the
applicable tariff rate through the balancing account of the purchased gas
adjustment provisions of Chattanooga's rate schedules.
Accounting Developments
In October 1995 the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 123, "Accounting for Stock-Based
Compensation" (SFAS 123). The adoption of the new recognition provisions for
stock-based compensation expense included in SFAS 123 are optional; however, the
pro forma effects on net income and earnings per share, had the recognition
provisions been adopted, are required to be disclosed in the fiscal 1997
financial statements. AGL Resources will continue to follow the requirements of
Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to
Employees," in its accounting for employee stock options; therefore, no impact
on the consolidated financial statements is expected.
<PAGE>
<PAGE>
<TABLE>
<CAPTION>
Statements of Consolidated Income
For the years ended September 30,
In millions, except per share amounts 1996 1995 1994
--------------------------------
<S> <C> <C> <C>
Operating Revenues ................................ $1,220.2 $1,063.0 $1,199.9
Cost of Gas ....................................... 720.3 571.8 736.8
--------------------------------
Operating Margin .................................. 499.9 491.2 463.1
--------------------------------
Other Operating Expenses
Operation ................................ 220.8 213.5 207.0
Restructuring costs ...................... 70.3
Maintenance .............................. 29.4 30.4 32.8
Depreciation ............................. 62.5 58.5 55.4
Taxes other than income taxes ............ 24.9 25.6 26.0
--------------------------------
Total other operating expenses .. 337.6 398.3 321.2
--------------------------------
Operating Income .................................. 162.3 92.9 141.9
--------------------------------
Other Income ...................................... 14.3 2.1 5.2
--------------------------------
Income Before Interest and Income Taxes ........... 176.6 95.0 147.1
--------------------------------
Interest Expense and Preferred
Stock Dividends
Interest on long-term debt ............... 42.2 42.7 43.2
Other interest ........................... 6.9 4.8 4.4
Dividends on preferred stock of subsidiary 4.4 4.4 4.5
Total interest expense and
preferred stock dividends .... 53.5 51.9 52.1
--------------------------------
Income Before Income Taxes ........................ 123.1 43.1 95.0
--------------------------------
Income Taxes ...................................... 47.5 16.7 36.3
--------------------------------
Net Income ........................................ $ 75.6 $ 26.4 $ 58.7
--------------------------------
Earnings Per Share of Common Stock (Note 5) ....... $ 1.37 $ 0.50 $ 1.17
--------------------------------
Weighted Average Number of Common
Shares Outstanding (Note 5) .............. 55.3 52.4 50.2
- ------------------------------------------------------------------------------------------
See notes to consolidated financial statements ....
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Statements of Consolidated Cash Flows
For the years ended September 30,
In millions 1996 1995 1994
---------------------------
<S> <C> <C> <C>
Cash Flows from Operating Activities
Net income .............................................. $ 75.6 $ 26.4 $ 58.7
Adjustments to reconcile net income to
net cash flow from operating activities
Depreciation and amortization .................. 67.5 62.5 59.2
Noncash restructuring costs .................... 52.9
Deferred income taxes .......................... 25.7 (1.2) 13.6
Other .......................................... 0.4 3.8 6.3
---------------------------
169.2 144.4 137.8
Changes in assets and liabilities
Receivables .................................... (29.6) 14.6 9.4
Inventories .................................... (35.8) 43.3 (38.5)
Deferred purchased gas adjustment .............. (11.0) (13.8) 20.8
Accounts payable ............................... 1.4 14.7 (6.0)
Other-- net .................................... (12.3) 2.4 4.7
---------------------------
Net cash flow from operating activities 81.9 205.6 128.2
---------------------------
Cash Flows from Financing Activities
Sale of common stock, net of expenses ................... 1.8 50.4 2.4
Short-term borrowings, net .............................. 101.0 (44.4) (36.0)
Redemptions and purchase fund
requirements of preferred stock
and long-term debt ............................. (15.0) (125.7)
Sale of long-term debt .................................. 194.5
Dividends paid on common stock .......................... (49.1) (44.3) (42.9)
---------------------------
Net cash flow from financing activities ........ 53.7 (53.3) (7.7)
---------------------------
Cash Flows from Investing Activities
Utility plant expenditures .............................. (132.0) (120.8) (122.0)
Cash received from joint venture ........................ 3.1
Investment in joint ventures ............................ (1.0) (32.6)
Other ................................................... (0.7) 1.5 1.5
---------------------------
Net cash flow from investing activities ........ (130.6) (151.9) (120.5)
---------------------------
Net increase in cash and cash equivalents ...... 5.0 0.4
Cash and cash equivalents at
beginning of year ..................... 3.7 3.3 3.3
---------------------------
Cash and cash equivalents at end of year ...... $ 8.7 $ 3.7 $ 3.3
---------------------------
Cash Paid During the Year for
Interest ................................................ $ 49.2 $ 48.4 $ 51.1
Income taxes ............................................ $ 19.3 $ 28.6 $ 18.0
- --------------------------------------------------------------------------------------------------
See notes to consolidated financial statements ...................
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Consolidated Balance Sheets
Assets September 30,
In millions 1996 1995
--------------------
<S> <C> <C>
Current Assets
Cash and cash equivalents ..................................... $ 8.7 $ 3.7
Receivables
Gas (less allowance for uncollectible
accounts of $2.2 in 1996 and $2.4 in 1995) .. 62.4 30.3
Merchandise (less allowance for uncollectible
accounts of $.4 in 1996 and $1.9 in 1995) ... 2.5 5.3
Integrated Resource Plan loans (less allowance
for uncollectible accounts of $.2 in 1996 and
$.1 in 1995) ................................ 3.4 1.3
Other ................................................ 4.8 9.6
Unbilled revenues ............................................. 20.5 17.5
Inventories
Natural gas stored underground ....................... 144.0 111.2
Liquefied natural gas ................................ 16.8 14.3
Materials and supplies ............................... 8.1 8.0
Other ................................................ 3.0 2.6
Deferred purchased gas adjustment ............................. 4.7
Other ......................................................... 10.3 10.9
--------------------
Total current assets ................................. 289.2 214.7
--------------------
Property, Plant and Equipment
Utility plant ................................................. 1,969.0 1,919.9
Less accumulated depreciation ................................. 607.8 583.3
--------------------
Utility plant-- net .................................. 1,361.2 1,336.6
--------------------
Nonutility property ........................................... 80.5 16.6
Less accumulated depreciation ................................. 26.3 2.9
--------------------
Nonutility property-- net ............................ 54.2 13.7
--------------------
Total property, plant and equipment-- net ............ 1,415.4 1,350.3
--------------------
Deferred Debits and Other Assets
Unrecovered environmental response costs ...................... 38.0 34.9
Investment in joint ventures .................................. 35.5 32.6
Unrecovered Integrated Resource Plan costs .................... 10.0 9.9
Unrecovered postretirement benefits costs ..................... 9.7 7.2
Unamortized cost to repurchase long-term debt ................. 3.5 4.9
Other ......................................................... 23.4 20.1
--------------------
Total deferred debits and other assets ............... 120.1 109.6
--------------------
Total Assets ......................................... $1,824.7 $1,674.6
- -------------------------------------------------------------------------------------------------
See notes to consolidated financial statements
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Liabilities and Capitalization September 30,
In millions 1996 1995
----------------------
<S> <C> <C>
Current Liabilities
Accounts payable-- trade ................................ $ 73.7 $ 72.3
Short-term debt ......................................... 152.0 51.0
Customer deposits ....................................... 27.8 29.5
Interest ................................................ 25.7 25.4
Other accrued liabilities ............................... 22.5 11.9
Take-or-pay charges payable ............................. 8.0
Deferred purchased gas adjustment ....................... 6.3
Other ................................................... 20.8 26.5
----------------------
Total current liabilities ...................... 322.5 230.9
----------------------
Accumulated Deferred Income Taxes ................................ 168.5 138.8
----------------------
Long-Term Liabilities
Accrued environmental response costs .................... 30.4 28.6
Accrued pension costs ................................... 4.9 10.3
Accrued postretirement benefits costs ................... 36.2 30.1
----------------------
Total long-term liabilities .................... 71.5 69.0
----------------------
Deferred Credits
Unamortized investment tax credit ....................... 28.8 30.3
Regulatory tax liability ................................ 19.3 23.3
Other ................................................... 12.8 12.0
----------------------
Total deferred credits ......................... 60.9 65.6
----------------------
Commitments and Contingencies (Notes 9 and 11)
Capitalization
Long-term debt .......................................... 554.5 554.5
Preferred stock
Cumulative preferred stock of subsidiary
Redeemable ............................ 55.5 55.5
Nonredeemable ......................... 3.0 3.0
Common stockholders' equity (See accompanying
statements of consolidated common stock equity.) 588.3 557.3
----------------------
Total capitalization .................................... 1,201.3 1,170.3
----------------------
Total Liabilities and Capitalization ............................. $1,824.7 $1,674.6
----------------------
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
Statements of Consolidated Common Stock Equity
For the years ended September 30,
In millions, except per share amounts 1996 1995 1994
----------------------------
<S> <C> <C> <C>
Common Stock (Note 5)
$5 par value; authorized 100.0 shares;
outstanding, 55.7 in 1996, 54.9 in 1995
and 50.8 in 1994
Beginning of year ........................................ $ 137.3 $ 127.1 $ 124.2
Issuance of common stock
Stock dividend ......................... 137.5
Public sale ............................ 7.5
Benefit, stock compensation,
dividend reinvestment and
stock purchase plans .......... 3.6 2.7 2.9
----------------------------
End of year .............................................. 278.4 137.3 127.1
----------------------------
Premium on Capital Stock (Note 5)
Beginning of year ........................................ 297.7 241.3 224.2
Issuance of common stock
Stock dividend ......................... (137.5)
Public sale ............................ 41.1
Benefit, stock compensation,
dividend reinvestment and
stock purchase plans .......... 10.4 15.3 17.1
----------------------------
End of year .............................................. 170.6 297.7 241.3
----------------------------
Earnings Reinvested
Beginning of year ........................................ 122.3 150.1 143.6
Net income ...................................... 75.6 26.4 58.7
Cash dividends
Common stock ($1.06 a share in 1996,
$1.04 a share in 1995 and 1994) (58.6) (54.2) (52.2)
----------------------------
End of year .............................................. 139.3 122.3 150.1
----------------------------
Total common stock equity ....................... $ 588.3 $ 557.3 $ 518.5
- ---------------------------------------------------------------------------------------------------
See notes to consolidated financial statements.
</TABLE>
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Summary of Significant Accounting Policies
Principles of Consolidation
AGL Resources Inc. (AGL Resources) is a Georgia corporation incorporated on
November 27, 1995, for the primary purpose of becoming the holding company for
Atlanta Gas Light Company (AGLC), AGLC's wholly owned natural gas utility
subsidiary, Chattanooga Gas Company (Chattanooga), and AGLC's nonregulated
subsidiaries. The holding company formation was completed upon receipt of
shareholder approval on March 6, 1996, when each share of AGLC common stock was
converted into one share of AGL Resources common stock, and AGLC became the
primary subsidiary of AGL Resources. AGLC comprises substantially all of AGL
Resources' assets, revenues and earnings. The consolidated financial statements
of AGL Resources include the financial statements of AGLC, Chattanooga and the
nonregulated subsidiaries as though AGL Resources had existed in all periods
shown and had owned all of AGLC's outstanding common stock prior to March 6,
1996. Intercompany balances and transactions have been eliminated.
Subsidiaries
AGL Resources engages in natural gas distribution through AGLC and AGLC's wholly
owned subsidiary, Chattanooga. AGLC is a public utility that distributes and
transports natural gas in Georgia and Tennessee and is subject to regulation by
the Georgia Public Service Commission (Georgia Commission) and the Tennessee
Regulatory Authority (TRA), formerly the Tennessee Public Service Commission,
with respect to its rates for service, maintenance of its accounting records and
various other matters. The consolidated financial statements are prepared in
accordance with generally accepted accounting principles, which give appropriate
recognition to the rate-making and accounting practices and policies of the
Georgia Commission and the TRA.
AGL Resources engages in nonregulated business activities through its wholly
owned subsidiaries, AGL Energy Services, Inc., a gas supply services company;
AGL Investments, Inc. (AGL Investments), a subsidiary established to develop and
manage certain nonregulated businesses; The Energy Spring, Inc., a retail energy
marketing company; and their subsidiaries.
Ownership of AGLC's nonregulated business, Georgia Gas Company (natural gas
production activities), has been transferred to AGL Energy Services, Inc.
Ownership of AGLC's other nonregulated businesses, Georgia Energy Company
(natural gas vehicle conversions), Georgia Gas Service Company (retail propane
sales) and Trustees Investments, Inc. (real estate holdings), has been
transferred to AGL Investments. AGLC's interest in Sonat Marketing Company L.P.
has been transferred to AGL Gas Marketing, Inc., a wholly owned subsidiary of
AGL Investments. In addition, AGL Investments has established two wholly owned
subsidiaries: AGL Power Services, Inc., which owns a 35% interest in Sonat Power
Marketing L.P., and AGL Consumer Services, Inc., an energy-related consumer
products and services company.
AGL Resources Service Company (Service Company) was formed during fiscal 1996 to
provide corporate support services to AGL Resources and its subsidiaries. The
transfer of related assets from AGLC to Service Company and other nonregulated
subsidiaries was effected through a noncash dividend during the fourth quarter
of fiscal 1996. Expenses of Service Company are allocated to AGL Resources and
its subsidiaries.
<PAGE>
Regulation The consolidated financial statements reflect regulatory actions by
the Georgia Commission and the TRA that result in the recognition of revenues
and expenses in different time periods than enterprises that are not rate
regulated. In accordance with Statement of Financial Accounting Standards No.
71, "Accounting for the Effects of Certain Types of Regulation" (SFAS 71),
regulatory assets and liabilities are recorded and represent regulator-approved
deferrals resulting from the rate-making process. SFAS 71 assets and liabilities
recorded on September 30 consist of the following:
(Millions of dollars) 1996 1995
---------------
Assets:
Unrecovered environmental
response costs ........ $ 38.0 $ 34.9
Unrecovered integrated
resource plan costs ... 10.0 9.9
Unrecovered postretirement
benefits costs ........ 9.7 7.2
Deferred purchased gas
adjustment ............ 4.7
Unamortized cost to
repurchase long-term
debt .................. 3.4 4.9
---------------
Total .................... $ 65.8 $ 56.9
===============
Liabilities:
Unamortized investment
tax credit ............ $ 28.8 $ 30.3
Regulatory tax liability . 19.3 23.3
Deferred purchased gas
adjustment ............ 6.3
Environmental response
cost recoveries from
third parties ........ 7.4
Environmental response
cost recoveries from
third parties --
customer portion ...... 4.5
Other .................... 3.7 15.0
---------------
Total .................... $ 63.7 $ 74.9
===============
Utility Plant and Depreciation
Utility plant is stated at original cost. Direct labor and material costs of
plant construction and related indirect construction costs, including
administrative, engineering and general overhead, taxes, and an allowance for
funds used during construction (AFUDC), are added to utility plant. The portion
of AFUDC attributable to equity funds is included in other income, and the
portion attributable to borrowed funds is shown as a reduction in interest
charges in the statements of consolidated income. The AFUDC rate of 9.32% in
fiscal 1996, 1995 and 1994, was the cost of capital approved by the Georgia
Commission in a prior rate proceeding.
The original cost of utility property retired or otherwise disposed of, plus the
cost of dismantling, less salvage, is charged to accumulated depreciation.
Maintenance, repairs and minor additions, renewals, and betterments to property
are charged to operations.
The composite straight-line depreciation rate was approximately 3.2% for utility
property other than transportation equipment during 1996, 1995 and 1994.
Transportation equipment is depreciated over a period of five to 10 years.
Deferred Purchased Gas Adjustment
The utility's rate schedules include purchased gas adjustment provisions that
permit the recovery of purchased gas costs. The purchased gas adjustment factor
is revised periodically to reflect changes in the cost of purchased gas without
formal rate proceedings. Any overrecoveries or underrecoveries of gas costs are
charged or credited to cost of gas and are included in current assets or
liabilities.
As part of the 1997 Gas Supply Plan, AGLC is authorized to continue limited gas
supply hedging activities. The 1997 hedging program has been expanded beyond the
program approved in the 1996 Gas Supply Plan. Accounting for hedging activities
is provided in accordance with Statement of Financial Accounting Standards No.
80, "Accounting for Futures Contracts." The financial results of all hedging
activities are passed through to firm service customers under the purchased gas
provisions of the utility's rate schedules. Accordingly, there is no earnings
impact as a result of the hedging program.
Operating Revenues
Revenues from AGL Resources' utility business are based on rates approved by the
Georgia Commission and the TRA. Customers' base rates may not be changed without
formal approval of the Georgia Commission or the TRA. Revenues are recognized on
the accrual basis, which includes estimated amounts for gas delivered but not
yet billed.
The Georgia Commission and the TRA have authorized weather normalization
adjustment riders. Such riders are designed to offset the impact that unusually
cold or warm weather has on operating margin.
Certain interruptible customers purchase gas directly from gas producers and
marketers. The Georgia Commission and the TRA have approved programs whereby
transportation charges are billed on those purchases.
Income Taxes
Deferred income taxes result from temporary differences between book and taxable
income and principally relate to depreciation.
Investment tax credits have been deferred and are being amortized by credits to
income in accordance with regulatory treatment over the estimated lives of the
related properties.
Statement of Cash Flows
For purposes of reporting cash flows, AGL Resources considers all highly liquid
investments purchased with a maturity of three months or less to be cash
equivalents.
Noncash investing and financing transactions include the issuance of common
stock for the Dividend Reinvestment and Stock Purchase Plan, Retirement Savings
Plus Plan, Long-Term Stock Incentive Plan, Nonqualified Savings Plan and the
Non-Employee Directors Equity Compensation Plan of $14.1 million in 1996, $16.2
million in 1995, and $17.6 million in 1994.
<PAGE>
Use of Estimates
Preparing financial statements in conformity with generally accepted accounting
principles requires management to make estimates and assumptions. Those
estimates and assumptions affect the reported amounts of assets and liabilities,
disclosure on contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
Other
Gas inventories are stated at cost on a principally first-in, first-out method.
Materials and supplies inventories are stated at lower of average cost or
market.
Consistent with the rate treatment prescribed by the Georgia Commission and the
TRA, vacation pay and short-term disability benefits for AGLC are expensed when
those benefits are paid.
The computation of earnings per share of common stock is based on the weighted
average number of common shares outstanding during each year as adjusted for the
two-for-one stock split on December 1, 1995. (See Note 5.)
Certain reclassifications have been made in 1995 and 1994 to conform with the
1996 financial statement presentation.
Recently Issued Accounting Pronouncements
In October 1995 the Financial Accounting Standards Board issued Statement of
Financial Accounting Standards No. 123, "Accounting for Stock-Based
Compensation" (SFAS 123). The adoption of the new recognition provisions for
stock-based compensation expense included in SFAS 123 is optional; however, the
pro forma effects on net income and earnings per share, had the recognition
provisions been adopted, are required to be disclosed in the fiscal 1997
financial statements. AGL Resources will continue to follow the requirements of
Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to
Employees," in its accounting for employee stock options; therefore, no impact
on the consolidated financial statements is expected.
2. Income Tax Expense
Deferred tax balances are measured at the tax rates that will apply during the
period the taxes become payable and are adjusted whenever new rates are enacted.
Due to the regulated nature of the utility's business, a regulatory liability
has been recorded in accordance with Statement of Financial Accounting Standards
No. 109, "Accounting for Income Taxes." The regulatory liability is being
amortized over approximately 30 years.
Components of income tax expense shown in the consolidated income statements are
as follows:
(Millions of dollars) 1996 1995 1994
--------------------------
Included in expenses:
Current income taxes
Federal ............... $ 20.3 $ 16.9 $ 20.9
State ................. 3.0 2.6 3.3
Deferred income taxes
Federal ............... 21.6 (1.0) 12.0
State ................. 4.1 (0.2) 1.6
Amortization of investment
tax credits ........... (1.5) (1.6) (1.5)
--------------------------
Total .................... $ 47.5 $ 16.7 $ 36.3
==========================
A reconciliation between the statutory federal income tax rate and the effective
rate is as follows:
(Millions of dollars) 1996
- -----------------------------------------------
% of
Pretax
Amount Income
- -----------------------------------------------
Computed tax expense ...... $ 43.1 35.0
State income tax,
net of federal income
tax benefit ............ 4.3 3.5
Amortization of
investment tax credits . (1.5) (1.2)
Other-- net ............... 1.6 1.3
- -----------------------------------------------
Total income tax expense $ 47.5 38.6
===============================================
(Millions of dollars) 1995
- -----------------------------------------------
% of
Pretax
Amount Income
- -----------------------------------------------
Computed tax expense ....... $ 15.1 35.0
State income tax,
net of federal income
tax benefit ............. 1.3 3.0
Amortization of
investment tax credits .. (1.6) (3.7)
Other-- net ................ 1.9 4.4
- -----------------------------------------------
Total income tax expense $ 16.7 38.7
===============================================
(Millions of dollars) 1994
- -----------------------------------------------
% of
Pretax
Amount Income
- -----------------------------------------------
Computed tax expense ....... $ 33.3 35.0
State income tax,
net of federal income
tax benefit ............. 3.2 3.4
Amortization of
investment tax credits .. (1.5) (1.6)
Other-- net ................ 1.3 1.4
- -----------------------------------------------
Total income tax expense $ 36.3 38.2
===============================================
Components that give rise to the net deferred income tax liability as of
September 30 are as follows:
(Millions of dollars) 1996 1995
- ---------------------------------------------------
Deferred tax liabilities:
Property -- accelerated
depreciation and other
property-related items .... $ 204.4 $ 187.1
Other ........................ 17.2 15.8
- ---------------------------------------------------
Total deferred tax liabilities 221.6 202.9
- ---------------------------------------------------
Deferred tax assets:
Deferred investment
tax credits ............... 11.1 11.7
Alternative minimum tax ...... 11.8 12.3
Other ........................ 30.2 40.1
- ---------------------------------------------------
Total deferred tax assets .... 53.1 64.1
- ---------------------------------------------------
Net deferred tax liability ... $ 168.5 $ 138.8
===================================================
3. Corporate Restructuring
In November 1994 AGL Resources announced a corporate restructuring plan and
began its implementation during fiscal 1995. As a result of the restructuring,
AGLC combined offices, established centralized customer service centers and
reduced the average number of employees through voluntary retirement, severance
programs and attrition. Restructuring costs of $43.1 million, after income
taxes, were recorded during 1995. The principal effects of the restructuring
charges were to increase obligations with respect to pension benefits and
postretirement benefits other than pensions.
During the fourth quarter of fiscal 1996, AGL Resources reviewed its remaining
liabilities with respect to its corporate restructuring plan. As a result, AGL
Resources adjusted its restructuring accruals and reduced operating expenses by
$2.7 million. The remaining balance of restructuring
<PAGE>
liabilities as of September
30, 1996, and 1995 was $1 million and $4.8 million, respectively.
4. Employee Benefit Plans
Effective July 1, 1996, the Board of Directors authorized the transfer of the
sponsorship of all employee benefit plans from AGLC to AGL Resources.
Substantially all employees of AGL Resources and its subsidiaries are eligible
to participate in the benefit plans.
AGL Resources has a noncontributory defined benefit retirement plan. The plan's
assets consist primarily of marketable securities, corporate obligations, U.S.
government obligations, insurance contracts, real estate investments and cash
equivalents. The plan provides pension benefits that are based on years of
service and the employee's highest 36 consecutive months' compensation out of
the last 60 months worked. AGL Resources' funding policy is to make the annual
contribution required by applicable regulations and recommended by its actuary.
AGL Resources has an excess benefit plan that is unfunded and provides
supplemental benefits to certain officers after retirement. In September 1994,
AGL Resources established a voluntary early retirement plan for certain officers
of AGL Resources that is unfunded and provides supplemental pension benefits to
participants who elected early retirement. The annual expense and accumulated
benefits of such plans are not significant.
Net periodic pension costs for the plans include service cost, interest cost,
return on pension assets and straight-line amortization of unrecognized initial
net assets over approximately 16 years. Net periodic pension costs include the
following components:
(Millions of dollars) 1996 1995 1994
- ------------------------------------------------------------------
Service cost ...................... $ 4.0 $ 4.5 $ 5.5
Interest cost ..................... 15.8 14.9 13.2
Actual return on assets ........... (19.3) (17.0) (3.3)
Net amortization and
deferral ....................... 6.3 5.9 (6.2)
- ------------------------------------------------------------------
Net periodic
pension cost ................ $ 6.8 $ 8.3 $ 9.2
- ------------------------------------------------------------------
Actuarial assumptions used include:
Discount rate ..................... 7.8% 8.3% 8.3%
Rate of increase in
compensation levels ............ 4.5% 5.0% 5.0%
Expected long-term
rate of return
on assets ...................... 8.3% 8.3% 8.3%
==================================================================
The following schedule sets forth the plans' funded status as of June 30, 1996,
and 1995, and amounts recognized in the consolidated balance sheets as of
September 30, 1996, and 1995:
(Millions of dollars) 1996 1995
- -----------------------------------------------------
Actuarial present value
of benefit obligations
Vested benefit obligation ..... $ 180.5 $ 175.6
- -----------------------------------------------------
Accumulated benefit||
obligation ................. $ 183.2 $ 178.3
- -----------------------------------------------------
Projected benefit obligation .. $ (212.9) $ (207.4)
Plan assets at fair value ..... 181.8 163.9
- -----------------------------------------------------
Plan assets less than projected
benefit obligation ........ (31.1) (43.5)
Unrecognized net loss ......... 26.8 34.1
Remaining unrecognized
net assets at date of
initial adoption ........... (4.5) (5.2)
Unrecognized prior
service cost ............... 3.9 4.3
- -----------------------------------------------------
Accrued pension costs ......... $ (4.9) $ (10.3)
=====================================================
During 1995 a curtailment loss of $6 million and a loss associated with
incentive benefits of $25.3 million were incurred as a result of a corporate
restructuring plan. (See Note 3.) The effect of the curtailment loss and
incentive loss was to increase the accumulated benefit obligation and projected
benefit obligation by $25.3 million and $31.3 million, respectively.
AGL Resources' Retirement Savings Plus Plan (RSP Plan), a 401(k) plan, provides
participants a mechanism for making contributions for retirement savings. Each
participant may contribute amounts up to 15% of eligible compensation. AGL
Resources makes a contribution equal to 65% of the participant's contribution
not to exceed 3.9% of the participant's compensation for the plan year. The
contribution was $3.2 million for 1996, $3.3 million for 1995 and $3.4 million
for 1994.
AGL Resources' Nonqualified Savings Plan (NSP), an unfunded, nonqualified plan
similar to the RSP Plan, was established on July 1, 1995. The NSP provides an
opportunity for eligible employees to make contributions for retirement savings.
AGL Resources' contributions during 1996 and 1995 to the NSP were not
significant.
In January 1988, in connection with a Leveraged Employee Stock Ownership Plan
(LESOP), AGL Resources purchased 2 million shares of its common stock for $11.75
per share, with the proceeds of a loan secured by such common stock. AGL
Resources has not guaranteed the repayment of the loan. The loan is expected to
be repaid from regular cash dividends on AGL Resources' common stock paid to the
LESOP and from contributions to the LESOP, as approved by AGL Resources' Board
of Directors. Contributions to the LESOP were $0.7 million for 1996, $0.8
million for 1995 and $0.8 million for 1994. The principal balance of the loan
was $2.9 million as of September 30, 1996, and $5.3 million as of September 30,
1995. The loan is payable on December 31, 1997.
AGL Resources' Long-Term Stock Incentive Plan (LTSIP) provides that incentive
and nonqualified stock options, restricted stock and stock appreciation rights
may be granted to key employees of AGL Resources and its subsidiaries. The
exercise price of any shares under option must be at least equal to the fair
market value on the date of the grant. The options granted become exercisable
six months after the date of grant and generally expire 10 years after the date
of grant.
<PAGE>
Option transactions during the three years ended September 30, 1996, are as
follows:
Shares Exercise Price
- -------------------------------------------------
Outstanding
September 30, 1993 388,344 $ 13.75-21.13
Granted .......... 234,994 18.56
Exercised ........ (4,000) 13.75
Forfeited ........ (21,626) 20.44-20.81
- -------------------------------------------------
Outstanding
September 30, 1994 597,712 $ 13.75-21.13
Granted .......... 325,576 16.00-19.25
Exercised ........ (46,264) 13.75-18.94
Forfeited ........ (11,508) 15.94-20.44
- -------------------------------------------------
Outstanding
September 30, 1995 865,516 $ 13.75-21.13
Granted .......... 299,340 19.75-20.88
Exercised ........ (107,648) 13.75-19.31
Forfeited ........ (43,532) 18.56-20.50
- -------------------------------------------------
Outstanding
September 30, 1996 1,013,676 $ 13.75-21.13
=================================================
As of September 30, 1996, and 1995, there were 1,008,498 and 714,336 options,
respectively, which were exercisable. As of September 30, 1996, 2,859,285 shares
were reserved under the LTSIP.
In addition to providing pension benefits, AGL Resources provides certain health
care and life insurance benefits for retired employees. Substantially all
employees become eligible for those benefits if they reach retirement age while
working for AGL Resources.
In 1993 the Georgia Commission approved a five-year phase-in of Statement of
Financial Accounting Standards No. 106, "Employers' Accounting for
Postretirement Benefits Other Than Pensions" (SFAS 106) that defers a portion of
SFAS 106 expense for future recovery. A regulatory asset has been recorded for
the deferred portion of SFAS 106 expense. In 1993 the TRA approved the recovery
of SFAS 106 expense that is funded through an external trust.
Net periodic postretirement benefits costs for fiscal 1996 and 1995 include the
following components:
(Millions of dollars) 1996 1995 1994
- -----------------------------------------------------
Service cost ........... $ 0.8 $ 0.9 $ 1.0
Interest cost .......... 8.8 7.6 6.5
Actual return on assets (0.6) (0.3)
Amortization of
transition obligation 4.2 4.2 4.1
- -----------------------------------------------------
Net postretirement
benefits costs ...... $ 13.2 $ 12.4 $ 11.6
=====================================================
Approximately $10.7 million, $8.7 million and $8.0 million of net periodic
postretirement benefits costs for fiscal 1996, 1995 and 1994, respectively, were
recovered from the utility's customers. The remaining $2.5 million, $3.7 million
and $3.6 million for 1996, 1995 and 1994, respectively, were deferred for future
recovery through amortization and recognized as a regulatory asset in the
financial statements consistent with regulatory decisions. AGL Resources has
funded, through an external trust, SFAS 106 expense recovered from its utility
customers in excess of the pay-as-you-go amounts.
The following schedule sets forth the plan's funded status as of September 30,
1996, and 1995:
(Millions of dollars) 1996 1995
- -------------------------------------------------
Retirees .................. $ 85.8 $ 94.1
Fully eligible active
plan participants ...... 6.4 9.3
Other active plan
participants ........... 13.3 14.5
- -------------------------------------------------
Total accumulated
postretirement benefit
obligation ............. 105.5 117.9
Plan assets at fair value . 10.4 8.0
- -------------------------------------------------
Accumulated postretirement
benefit obligation
in excess of plan assets 95.1 109.9
Unrecognized transition
obligation ............. (69.5) (73.6)
Unrecognized gain (loss) .. 10.6 (6.2)
- -------------------------------------------------
Accrued postretirement
benefits costs ......... $ 36.2 $ 30.1
=================================================
During 1995 a curtailment loss of $22.9 million was incurred as a result of a
corporate restructuring. (See Note 3.) The assumed health care cost trend rate
used in measuring the accumulated postretirement benefit obligation for
pre-Medicare eligibility is 11% in 1996, decreasing 0.5% per year to 6% in the
year 2006 and an additional 0.25% to 5.75% in 2007. The rate for post-Medicare
eligibility is 9.5% in 1996, decreasing 0.5% per year to 5.5% in the year 2004
and an additional 0.25% to 5.25% in 2005. Increasing the assumed health care
cost trend rate by 1% would increase the accumulated postretirement benefit
obligation as of September 30, 1996, by approximately $6 million and the accrued
postretirement benefits cost by approximately $0.5 million for fiscal 1996. The
assumed discount rate used in determining the postretirement benefit obligation
was 7.75% in 1996 and 1995.
5. Common Stock
On March 6, 1996, the Board of Directors of AGL Resources adopted the Rights
Agreement by and between AGL Resources and Wachovia Bank of North Carolina,
N.A., as rights agent. In connection with the agreement, the Board of Directors
declared a dividend of one preferred stock purchase right on each outstanding
share of common stock. The rights dividend was paid on March 22, 1996, to
shareholders of record on that date. The rights, as distributed, are not
exercisable until a distribution date, but in any event, no later than March 6,
2006. A distribution date will occur on the earlier of 10 days following the
public announcement that a person or group of persons has acquired beneficial
ownership of 10% or more of the outstanding shares of common stock or 10 days
following the commencement of or announcement of an intention of an acquiring
person to make a tender or exchange offer, the consummation of which would
result in such acquiring person owning 10% of the outstanding shares of common
stock.
In the event a distribution date occurs, the holder of a right can purchase from
AGL Resources one one-hundredth of a share of Class A Junior Participating
Preferred Stock at a purchase price of $60. Each share of preferred stock is
entitled to a minimum preferential quarterly dividend of $1 per share, but not
less than an aggregate
<PAGE>
dividend of 100 times the dividend declared on each share of common stock. Upon
liquidation, the holders of preferred stock will be entitled to a preferential
liquidation payment of $100 per share (plus accrued and unpaid dividends) but
not less than an aggregate payment of 100 times the payment on each share of
common stock. Each share of preferred stock will have 100 votes and will vote
together with common stock on any merger or consolidation or other transaction
in which shares of common stock are converted or exchanged, and each share of
preferred stock will receive 100 times the amount received per share of common
stock. One one-hundredth of a share of preferred stock purchasable upon exercise
of a right is intended to approximate the value of one share of common stock.
In the event that a distribution date occurs and AGL Resources is acquired in a
merger or other business combination, each holder of a right thereafter will
have the right to receive, upon exercise of the right at the then current
exercise price, that number of shares of common stock of the acquiring company,
which number of shares at the time of the transaction will have a market value
of two times the exercise price of the right. In addition, at any time after a
distribution date, the Board of Directors of AGL Resources may exchange the
rights for one share of common stock or one one-hundredth share of preferred
stock per right.
AGL Resources, at any time prior to a distribution date acting through its Board
of Directors, may redeem, in whole but not in part, each right at a purchase
price of $.01 per right. Immediately upon redemption of the rights, the right to
exercise will terminate.
On November 3, 1995, the Board of Directors declared a two-for-one stock split
of the common stock effected in the form of a 100% stock dividend to
shareholders of record on November 17, 1995, and payable on December 1, 1995.
AGL Resources recorded a decrease to premium on capital stock and an increase to
common stock of $137.5 million to transfer the amount of the par value of the
stock dividend to common stock. All references to number of shares and to per
share amounts have been restated retroactively to reflect the stock dividend.
On June 16, 1995, approximately 3 million shares of common stock were issued and
sold at $16.81 per share, resulting in net proceeds of $48.6 million. Proceeds
from that sale of common stock were used to finance capital expenditures and for
other corporate purposes.
AGL Resources also issued 762,553; 1,092,486; and 1,144,270 shares of its common
stock during the years ended September 30, 1996, 1995, and 1994, respectively,
to its Dividend Reinvestment and Stock Purchase Plan, RSP Plan, LTSIP, NSP and
the Non-Employee Directors Equity Compensation Plan.
As of September 30, 1996, 3,523,053 shares of common stock were reserved for
issuance pursuant to the Dividend Reinvestment and Stock Purchase Plan, RSP
Plan, LTSIP, NSP and the Non-Employee Directors Equity Compensation Plan.
6. Preferred Stock
AGLC is required under its charter to offer to purchase or call for redemption
4,100 shares of preferred stock for each of the five years ending September 30,
2001. The issues are callable at the option of AGLC, in whole or in part, upon
30 days' notice. Shares reacquired by AGLC to satisfy future requirements and
reported as if canceled were 6,715; 7,715; and 8,715, as of September 30, 1996,
1995, and 1994, respectively.
AGLC's charter contains provisions limiting the issuance of additional shares of
preferred stock. The most restrictive of those provisions requires gross income,
as defined, for a specified 12-month period to be at least equal to 1.5 times
the sum of annualized interest requirements on outstanding indebtedness and the
dividend requirements on outstanding preferred stock, including the preferred
stock being issued. Based on earnings for fiscal 1996, gross income was 2.47
times the sum of interest and preferred stock dividend requirements.
As of September 30, 1996, AGL Resources had 10 million shares of authorized, but
unissued, Class A Junior Participating Preferred Stock, no par value, and 10
million shares of authorized, but unissued, preferred stock, no par value. As of
September 30, 1996, Atlanta Gas Light Company had 10 million shares of
authorized, but unissued, preferred stock, no par value.
The outstanding preferred stock, net of current maturities, as of September 30
is as follows:
(Millions of dollars) 1996 1995
- -----------------------------------------------------
$100 par or stated value
(callable at option of AGLC)
Redeemable
preferred stock
4.72% -- Current call
price $103.00 ................. $ 1.5 $ 1.5
7.70%-- Current call
price (a) ..................... 44.5 44.5
7.84% -- Current call
price $101.96 ................. 4.6 4.6
8.32% -- Current call
price $102.08 ................. 4.9 4.9
Nonredeemable
preferred stock
4.50% -- Current call
price $105.25 ................. 2.0 2.0
5.00% -- Current call
price $105.00 ...... ......... 1.0 1.0
- -----------------------------------------------------
Total ............................ $ 58.5 $ 58.5
=====================================================
(a) Not redeemable prior to December 1, 1997. Redeemable at par thereafter.
The outstanding shares of preferred stock, net of previously reacquired shares
and shares reacquired during the year for purchase fund requirements, are as
follows:
1996 1995 1994
- -------------------------------------------
4.50% Series
Outstanding 20,000 20,000 20,000
4.72% Series
Outstanding 15,285 15,285 15,285
5.00% Series
Outstanding 10,000 10,000 10,000
7.70% Series
Outstanding 445,000 445,000 445,000
7.84% Series
Outstanding 47,645 47,797 47,802
Reacquired 152 5 1,500
8.32% Series
Outstanding 49,854 50,004 50,004
Reacquired 150 215
- -------------------------------------------
Total
Outstanding 587,784 588,086 588,091
Reacquired 302 5 1,715
===========================================
<PAGE>
7. Long-Term Debt
Medium-term notes Series A, Series B and Series C were issued under an Indenture
dated December 1, 1989. The notes are unsecured and rank on a parity with all
other unsecured indebtedness. During 1994, $194.5 million in principal amount of
such notes was issued. The annual maturities of long-term debt for the five
years ending September 30, 2001, are $50 million in 2000 and $20 million in
2001.
The outstanding long-term debt, net of current maturities, as of September 30 is
as follows:
(Millions of dollars) 1996 1995
- --------------------------------------
Medium-term notes
Series A (1) .... $ 60.0 $ 60.0
Series B (2) .... 300.0 300.0
Series C (3) .... 194.5 194.5
- --------------------------------------
Total ........ $ 554.5 $ 554.5
======================================
(1) Interest rates from 8.90% to 9.10% with maturity dates from 2000 to 2021
(2) Interest rates from 7.15% to 8.70% with maturity dates from 2000 to 2023.
(3) Interest rates from 5.90% to 7.20% with maturity dates from 2004 to 2024.
8. Short-Term Debt
Lines of credit with various banks provide for direct borrowings and are subject
to annual renewal. The current lines of credit vary throughout the year from $75
million in the summer months to $253 million for peak winter financing. Certain
of the lines are on a commitment fee basis. As of September 30, 1996, $59.3
million was available on lines of credit.
Short-term borrowings consisted of the following:
(Millions of dollars) 1996 1995 1994
- ---------------------------------------------------------------------------
Short-term debt
outstanding at
end of year .......................... $ 152.0 $ 51.0 $ 95.4
Maximum amounts
of short-term debt
outstanding at any
month end during
the year ............................. 156.3 155.0 229.4
Average amounts
of short-term debt
outstanding during
the year (a) ......................... 87.5 51.5 69.3
- ---------------------------------------------------------------------------
Weighted Average
Interest Rates ............................ 1996 1995 1994
- ---------------------------------------------------------------------------
Short-term debt
outstanding at
end of year .......................... 5.7% 5.9% 5.1%
Average amounts
of short-term debt
outstanding during
the year (a) ......................... 5.8% 5.7% 3.6%
============================================================================
(a) Average amount outstanding during the year calculated based on daily
outstanding balances. Weighted average interest rate during the year calculated
based on interest expense and average amount outstanding during the year.
9. Commitments and Contingencies
In connection with its utility business, AGL Resources has agreements for firm
pipeline and storage capacity that expire at various dates through 2012. The
aggregate amount of required payments under such agreements totals approximately
$1.1 billion, with annual required payments of $225 million in 1997, $218
million in 1998, $156 million in 1999, $107 million in 2000 and $78 million in
2001. Total payments of fixed charges under all agreements were $225 million in
1996, $230 million in 1995 and $232 million in 1994. The purchased gas
adjustment provisions of the utility's rate schedules permit the recovery of gas
costs from customers.
In 1992 the Federal Energy Regulatory Commission (FERC) issued Order 636, which,
among other things, mandated the unbundling of interstate pipeline sales service
and established certain open access transportation regulations that became
effective beginning in the 1993-1994 heating season. Order 636 permits the
utility's pipeline suppliers to pass through any prudently incurred transition
costs, such as unrecovered gas costs, gas supply realignment costs and stranded
costs. The utility estimates its portion of such costs from all of its pipeline
suppliers would approximate $109.9 million based on filings with FERC by the
pipeline suppliers. Approximately $80.6 million of such costs have been incurred
by the utility as of September 30, 1996, recovery of which is provided under the
purchased gas provisions of its rate schedules.
As part of the 1997 Gas Supply Plan, AGLC is authorized to continue limited gas
supply hedging activities. The 1997 hedging program has been expanded beyond the
program approved in the 1996 Gas Supply Plan. The financial results of all
hedging activities are passed through to firm service customers under the
purchased gas provisions of the utility's rate schedules. Accordingly, there is
no earnings impact as a result of the hedging program. Contracts outstanding as
of September 30, 1996, and during the year then ended, were not significant.
As of September 30, 1996, approximately 25% of AGL Resources' and its
subsidiaries' labor force was covered by collective bargaining agreements. A
collective bargaining agreement with the General Teamsters Local Union No. 528
expired on September 15, 1996. A new, four-year contract was finalized on
October 13, 1996. In addition, a new, five-year agreement with the Utility
Workers' Union of America, Local Union No. 461, became effective October 15,
1996.
Total rental expense for property and equipment was $7 million in 1996, $6.3
million in 1995 and $6.5 million in 1994. Minimum annual rentals under
noncancelable operating leases are as follows: 1997 -- $6.1 million; 1998 --
$5.6 million; 1999 -- $4.6 million; 2000 -- $4.1 million; 2001 -- $3.4 million;
and thereafter -- $6.3 million.
AGL Resources and its subsidiaries are involved in litigation arising in the
normal course of business. (See Note 11 regarding Environmental Matters.)
Management
<PAGE>
believes that the ultimate resolution of such litigation will not have a
material adverse effect on the consolidated financial statements.
10. Customers' and Suppliers' Refunds
Pursuant to orders of FERC, the utility has received refunds from its interstate
natural gas suppliers. Those refunds are a result of FERC orders adjusting the
price of various pipeline services purchased by the utility from its suppliers
in prior periods. The utility passes the refunds on to its customers under
purchased gas provisions of rate schedules approved by the Georgia Commission
and the TRA.
On August 23, 1995, the Georgia Commission approved a $38.5 million plus
interest refund of deferred purchased gas costs. The refund resulted from the
overrecovery of gas costs through the purchased gas provisions of the utility's
rate schedules. The refund was credited to customers' bills in September 1995.
On September 7, 1994, the Georgia Commission approved a $13.5 million refund of
deferred purchased gas costs. The refund resulted from the overrecovery of gas
costs through the purchased gas provisions of the utility's rate schedules. The
refund was credited to customers' bills in September 1994.
11. Environmental Matters
AGLC has identified nine sites in Georgia where it currently owns all or part of
a manufactured gas plant (MGP) site. In addition, AGLC has identified three
other sites in Georgia that AGLC does not now own, but that may have been
associated with the operation of MGPs by AGLC or its predecessors. There are
three sites in Florida that have been investigated by environmental authorities
in connection with which AGLC may be contacted as a potentially responsible
party. Preliminary assessments and subsequent site investigations have revealed
environmental impacts at and near some of those sites.
Under a thorough analysis of potentially applicable requirements, AGLC has
estimated that, under the most favorable circumstances reasonably possible, the
future cost of investigating and remediating the former MGP sites, excluding
sites for which no remediation is expected or the cost of which cannot be
estimated, could be as low as $30.4 million. Alternatively, AGLC has estimated
that, under the least favorable circumstances reasonably possible, the future
cost of investigating and remediating the same former MGP sites could be as high
as $110.8 million, excluding sites for which no remediation is expected or the
cost of which cannot be estimated. AGLC cannot estimate at this time the amount
of any other future expenses or liabilities, or the impact on those estimates of
future environmental or regulatory changes, that may be associated with or
related to the MGP sites, including expenses or liabilities relating to any
litigation. At the present time, no amount within the $30.4 million to $110.8
million range can be identified as a better estimate than any other estimate.
Therefore, a liability at the low end of this range and a corresponding
regulatory asset have been recorded in the financial statements.
The Georgia Commission has approved the recovery by AGLC of environmental
response costs, pursuant to AGLC's Environmental Response Cost Recovery Rider
(ERCRR). For purposes of the ERCRR, environmental response costs include
investigation, testing, remediation and litigation costs and expenses or other
liabilities relating to or arising from MGP sites. In connection with the ERCRR,
the staff of the Georgia Commission has undertaken a financial and management
process audit related to the MGP sites, cleanup activities at the sites and
environmental response costs that have been incurred for purposes of the ERCRR.
On October 10, 1996, the Georgia Commission issued an order to prohibit funds
collected through the ERCRR from being used for the payment of any damage award,
including punitive damages, as a result of any litigation associated with any of
the MGP sites in which AGLC is involved. AGLC is currently pursuing judicial
review of the October 10, 1996, order.
AGLC is currently a party to claims and litigation related to the former MGP
sites. During fiscal 1996 AGLC recovered $14.7 million from its insurance
carriers and other potentially responsible parties. In accordance with
provisions of the ERCRR, AGLC recognized other income of $2.9 million and
established regulatory liabilities for the remainder of those recoveries. AGLC
intends to continue to pursue insurance coverage and contributions from
potentially responsible parties.
12. Fair Value of Financial Instruments
AGL Resources has estimated the fair value of its financial instruments, the
carrying value of which differed from fair value, using available market
information and appropriate valuation methodologies. Considerable judgment is
required in developing the estimates of fair value presented herein and,
therefore, the values are not necessarily indicative of the amounts that could
be realized in a current market exchange.
The carrying amount and the estimated fair value of such financial instruments
as of September 30, 1996, and 1995, consist of the following:
Carrying Estimated
(Millions of dollars) Amount Fair Value
- ----------------------------------------------------
1996
Long-term debt
including current
portion .................. $ 554.5 $ 566.6
Redeemable
cumulative preferred
stock of AGLC,
including current
portion ................. 55.8 56.9
- ----------------------------------------------------
1995
Long-term debt
including current
portion ................. $ 554.5 $ 571.5
Redeemable
cumulative preferred
stock of AGLC,
including current
portion .................. 55.8 56.6
- ----------------------------------------------------
The estimated fair values are determined based on the following:
Long-term debt -- interest rates that are currently available for issuance of
debt with similar terms and remaining maturities.
Redeemable cumulative preferred stock -- quoted market price and dividend rates
for preferred stock with similar terms.
The fair value estimates presented herein are based on information available to
management as of September 30, 1996. Management is not aware of any subsequent
factors that would affect the estimated fair value amounts significantly.
13. Joint Ventures
During June 1996 Sonat Power Marketing, Inc., and AGL Power Services, Inc., a
wholly owned subsidiary of AGL Investments, Inc., together formed a joint
venture, Sonat Power Marketing L.P. AGL Power Services invested approximately $1
million for a 35% ownership interest in the partnership. Sonat Power Marketing
L.P. provides power marketing and all related services in key market areas
throughout the United States.
During August 1995 AGLC signed an agreement with Sonat Inc. (Sonat) to form a
joint venture to acquire the business of Sonat Marketing Company, a wholly owned
subsidiary of Sonat. The joint venture, Sonat Marketing Company L.P. (Sonat
Marketing), offers natural gas sales, transportation, risk management and
storage services to natural gas users and producers in key natural gas producing
and consuming areas of the United States.
AGLC invested $32.6 million for a 35% ownership interest in Sonat Marketing.
AGLC's 35% investment is being accounted for under the equity method. The excess
of the purchase price over the estimated fair value of the net tangible assets
of approximately $23 million has been allocated to intangible assets consisting
of customer lists and goodwill; those assets are being amortized over 10 and 35
years, respectively.
AGL Investments has certain rights for a period of five years to sell its
interest in Sonat Marketing to Sonat at a predetermined fixed price, as defined,
or for fair market value at any time.
During fiscal 1996 and September 1995, AGL Resources purchased gas totaling
$247.5 million and $23.7 million, respectively, from Sonat Marketing and its
affiliates. As of September 30, 1996, and 1995, AGL Resources had outstanding
obligations payable to Sonat Marketing of $18.8 million and $23.7 million,
respectively.
14. Quarterly Financial Data (Unaudited)
Quarterly financial data for fiscal 1996 and 1995 are summarized as follows:
(Millions, except
per share data) Operating Operating
Quarter Ended Revenues Income
(Loss)
- ---------------------------------------------
1996
December 31, 1995 ........ $ 328.8 $ 59.2
March 31, 1996 ........... 478.8 79.0
June 30, 1996 ............ 241.1 17.2
September 30, 1996 ....... 171.5 6.9
- ---------------------------------------------
1995 (a)
December 31, 1994 ........ $ 328.8 $ 14.7
March 31, 1995 ........... 448.2 67.3
June 30, 1995 ............ 177.5 13.3
September 30, 1995 (b) .. 108.5 (2.4)
- ---------------------------------------------
Earnings
(Loss)
Net Per Share of
Income Common Stock
Quarter Ended (Loss) (c)
- ---------------------------------------------
1996
December 31, 1995 ..... $ 29.1 $ 0.53
March 31, 1996 ........ 45.0 0.81
June 30, 1996 ......... 3.6 0.06
September 30, 1996 (d) (2.1) (0.04)
1995 (a)
- ---------------------------------------------
December 31, 1994 ..... $ 0.7 $ 0.01
March 31, 1995 ........ 36.2 0.70
June 30, 1995 ......... 0.3 0.01
September 30, 1995 .... (10.8) (0.20)
- ---------------------------------------------
(a) Quarterly operating income (loss) for 1995 includes the effects charges for
of restructuring costs as follows: $44.5 million for the quarter ended December
31, 1994; $23.0 million for the quarter ended March 31, 1995; $1.7 million for
the quarter ended June 30, 1995; and $1.1 million for the quarter ended
September 30, 1995.
Quarterly net income (loss) and earnings per share data for 1995 include the
effects of charges for restructuring costs as follows: $28.4 million and $0.56
for the quarter ended December 31, 1994; $13.0 million and $0.25 for the quarter
ended March 31, 1995; $1.1 million and $0.02 for the quarter ended June 30,
1995; and $0.6 million and $0.01 for the quarter ended September 30, 1995.
Earnings per share have been adjusted to reflect the effects of a two-for-one
stock split. (See Note 5.) The wide variance in quarterly earnings results from
the highly seasonal nature of AGL Resources' primary business.
(b) During the fourth quarter of fiscal 1995, AGLC recorded a refund to its
customers of $38.5 million plus interest. (See Note 10.)
(c) Earnings per share are calculated based on the weighted average number of
shares outstanding during the quarter. That total differs from the earnings per
share, as shown on the statements of consolidated income, which is based on the
weighted average number of shares outstanding for the entire year.
(d) During the fourth quarter of fiscal 1996, AGL Resources increased net income
and earnings per share by $1.6 million and $.03, respectively, as a result of a
review of remaining liabilities in connection with a corporate restructuring
plan. (See Note 3.)
In addition, net income and earnings per share were increased during the fourth
quarter of fiscal 1996 by $1.6 million and $.03, respectively, in connection
with recoveries from insurers in accordance with provisions of an environmental
response cost recovery rider. (See Note 11.)
<PAGE>
Independent Auditors' Report
To the Shareholders and Board of Directors of AGL Resources Inc.: We have
audited the accompanying consolidated balance sheets of AGL Resources Inc. and
subsidiaries as of September 30, 1996 and 1995, and the related statements of
consolidated income, common stock equity, and cash flows for each of the three
years in the period ended September 30, 1996. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits. We conducted our
audits in accordance with generally accepted auditing standards. Those standards
require that we plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material misstatement. An audit
includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by management as well
as evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion. In our opinion, such
consolidated financial statements present fairly, in all material respects, the
financial position of AGL Resources Inc. and subsidiaries as of September 30,
1996 and 1995, and the results of its operations and its cash flows for each of
the three years in the period ended September 30, 1996, in conformity with
generally accepted accounting principles.
Atlanta, Georgia
November 5, 1996 DELOITTE & TOUCHE LLP
<PAGE>
Management's Responsibility for Financial Reporting
The consolidated financial statements and related information are the
responsibility of management. The financial statements have been prepared in
conformity with generally accepted accounting principles appropriate in the
circumstances. The financial information contained elsewhere in this Annual
Report is consistent with that in the financial statements. The Company
maintains a system of internal accounting controls designed to provide
reasonable assurance that assets are safeguarded from loss and that transactions
are executed and recorded in accordance with established procedures. The concept
of reasonable assurance is based on the recognition that the cost of maintaining
a system of internal accounting controls should not exceed related benefits. The
system of internal accounting controls is supported by written policies and
guidelines. The financial statements have been audited by Deloitte & Touche LLP,
independent auditors. Their audits were made in accordance with generally
accepted auditing standards, as indicated in the Independent Auditors' Report,
and included a review of the system of internal accounting controls and tests of
transactions to the extent they considered necessary to carry out their
responsibilities. The Board of Directors pursues its responsibility for reported
financial information through its Audit Committee. The Audit Committee meets
periodically with management and the independent auditors to assure that they
are carrying out their responsibilities and to discuss internal accounting
controls, auditing and financial reporting matters.
David R. Jones J. Michael Riley
President and Chief Executive Vice President and Chief Financial
Officer Officer
<PAGE>
<TABLE>
<CAPTION>
SELECTED FINANCIAL DATA
For the years ended September 30,
In millions, except per share amounts 1996 1995 1994 1993 1992 1991
- ----------------------------------------------------------------------------------------------------------------------------------
Income Statement Data
<S> <C> <C> <C> <C> <C> <C>
Operating revenues ............................. $ 1,220.2 $ 1,063.0 $ 1,199.9 $ 1,130.3 $ 994.6 $ 963.8
Cost of gas .................................... 720.3 571.8 736.8 701.0 590.5 579.9
- ----------------------------------------------------------------------------------------------------------------------------------
Operating margin ............................... 499.9 491.2 463.1 429.3 404.1 383.9
- ----------------------------------------------------------------------------------------------------------------------------------
Other operating expenses
Operation .................................... 220.8 213.5 207.0 187.6 170.7 165.2
Restructuring costs .......................... 70.3
Maintenance .................................. 29.4 30.4 32.8 30.9 29.5 28.6
Depreciation ................................. 62.5 58.5 55.4 58.8 54.9 50.2
Taxes other than income taxes ................ 24.9 25.6 26.0 23.9 23.2 19.2
- ----------------------------------------------------------------------------------------------------------------------------------
Total other operating expenses ............. 337.6 398.3 321.2 301.2 278.3 263.2
- ----------------------------------------------------------------------------------------------------------------------------------
Operating income ............................... 162.3 92.9 141.9 128.1 125.8 120.7
- ----------------------------------------------------------------------------------------------------------------------------------
Other income ................................... 14.3 2.1 5.2 6.6 2.8 2.0
- ----------------------------------------------------------------------------------------------------------------------------------
Income before interest and income taxes ........ 176.6 95.0 147.1 134.7 128.6 122.7
- ----------------------------------------------------------------------------------------------------------------------------------
Interest expense and preferred stock dividends . 53.5 51.9 52.1 51.0 48.4 48.0
- ----------------------------------------------------------------------------------------------------------------------------------
Income before income taxes ..................... 123.1 43.1 95.0 83.7 80.2 74.7
- ----------------------------------------------------------------------------------------------------------------------------------
Income taxes ................................... 47.5 16.7 36.3 30.5 25.8 26.4
- ----------------------------------------------------------------------------------------------------------------------------------
Net Income ..................................... 75.6 26.4 58.7 53.2 54.4 48.3
Common dividends paid .......................... 58.6 54.2 52.2 51.1 49.6 47.4
- ----------------------------------------------------------------------------------------------------------------------------------
Earnings reinvested ............................ $ 17.0 $ (27.8) $ 6.5 $ 2.1 $ 4.8 $ 0.9
==================================================================================================================================
Common Stock Data(1)
Weighted average shares outstanding ............ 55.3 52.4 50.2 49.2 48.2 46.6
Earnings per share ............................. $ 1.37 $ 0.50 $ 1.17 $ 1.08 $ 1.13 $ 1.04
Dividends paid per share ....................... $ 1.06 $ 1.04 $ 1.04 $ 1.04 $ 1.03 $ 1.02
Dividend payout ratio .......................... 77.4% 208.0% 88.9% 96.3% 91.2% 98.1%
Book value per share(2) ........................ $ 10.56 $ 10.15 $ 10.20 $ 9.90 $ 9.70 $ 9.42
Market value per share(2) ...................... $ 19.13 $ 19.31 $ 15.31 $ 18.81 $ 18.81 $ 17.19
==================================================================================================================================
Balance Sheet Data(2)
Total assets ................................... $ 1,824.7 $ 1,674.6 $ 1,642.9 $ 1,533.0 $ 1,428.6 $ 1,350.3
Long-term liabilities
Take-or-pay charges payable .................. $ 5.0 $ 15.0
Accrued environmental response costs ......... $ 30.4 $ 28.6 $ 24.3 $ 19.6 $ 25.0
Accrued pension costs ........................ $ 4.9 $ 10.3
Accrued postretirement benefits costs ........ $ 36.2 $ 30.1 $ 3.6
Deferred credits ............................. $ 60.9 $ 65.6 $ 66.6 $ 42.3 $ 43.8 $ 47.6
- ----------------------------------------------------------------------------------------------------------------------------------
Capitalization
Long-term debt ............................... $ 554.5 $ 554.5 $ 569.5 $ 500.7 $ 476.5 $ 458.3
Preferred stock of subsidiary -- redeemable .. 55.8 55.8 55.8 56.0 11.5 12.8
-- nonredeemable 3.0 3.0 3.0 3.0 3.0 3.0
Common equity ................................ 588.3 557.3 518.5 492.0 472.1 448.2
- ----------------------------------------------------------------------------------------------------------------------------------
Total ...................................... $ 1,201.6 $ 1,170.6 $ 1,146.8 $ 1,051.7 $ 963.1 $ 922.3
==================================================================================================================================
Financial Ratios(2)
Capitalization
Long-term debt ............................... 46.1% 47.4% 49.6% 47.6% 49.5% 49.7%
Preferred stock of subsidiary -- redeemable .. 4.6 4.8 4.9 5.3 1.2 1.4
-- nonredeemable 0.3 0.2 0.3 0.3 0.3 0.3
Common equity ................................ 49.0 47.6 45.2 46.8 49.0 48.6
- ----------------------------------------------------------------------------------------------------------------------------------
Total ...................................... 100.0% 100.0% 100.0% 100.0% 100.0% 100.0%
==================================================================================================================================
Return on average common equity ................ 13.2% 4.9% 11.6% 11.0% 11.8% 11.4%
- ----------------------------------------------------------------------------------------------------------------------------------
Times charges earned before income taxes(3)
Total interest ............................... 3.58 1.99 3.08 2.86 2.66 2.56
Total interest and preferred dividends ....... 3.28 1.83 2.82 2.63 2.60 2.50
Fixed(4) ..................................... 3.47 1.95 3.00 2.80 2.62 2.53
==================================================================================================================================
(1) Adjusted for two-for-one stock split paid in the form of 100% stock
dividends on December 1, 1995. (2) Year end. (3) Interest charges exclude the
debt portion of allowance for funds used during construction. (4) Fixed charges
consist of interest on short- and long-term debt, other interest and the
estimated interest component of rentals.
</TABLE>
<PAGE>
<TABLE>
<CAPTION>
GAS SALES AND STATISTICS
For the years ended September 30,
In millions, except per share amounts 1996 1995 1994 1993 1992 1991
- ----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Operating Revenues (millions of dollars)
Sales of gas
Residential .................................. $ 708.8 $ 610.6 $ 700.7 $ 658.2 $ 575.7 $ 550.2
Commercial ................................... 288.8 243.2 285.8 268.1 231.5 226.0
Industrial ................................... 178.8 169.4 172.1 154.2 140.9 144.1
Transportation revenues ........................ 21.5 23.9 22.6 33.8 36.6 37.8
Miscellaneous revenues ......................... 19.7 15.9 18.7 16.0 9.9 5.7
- ----------------------------------------------------------------------------------------------------------------------------------
Total utility operating revenues ........... 1,217.6 1,063.0 1,199.9 1,130.3 994.6 963.8
- ----------------------------------------------------------------------------------------------------------------------------------
Other operating revenues ................... 2.6
- ----------------------------------------------------------------------------------------------------------------------------------
Total operating revenues ................. $ 1,220.2 $ 1,063.0 $ 1,199.9 $ 1,130.3 $ 994.6 $ 963.8
==================================================================================================================================
Utility Throughput
Therms sold (millions)
Residential .................................. 1,165.4 916.8 1,003.1 1,001.4 915.4 819.5
Commercial ................................... 538.2 454.0 478.9 478.5 433.9 402.8
Industrial ................................... 449.6 526.0 424.8 388.7 445.0 455.1
Therms transported ............................. 738.7 722.8 697.4 795.6 901.8 862.6
- ----------------------------------------------------------------------------------------------------------------------------------
Total utility throughput ................. 2,891.9 2,619.6 2,604.2 2,664.2 2,696.1 2,540.0
==================================================================================================================================
Average Utility Customers (thousands)
Residential .................................... 1,289.4 1,250.4 1,215.2 1,182.7 1,152.2 1,124.0
Commercial ..................................... 102.5 100.0 98.0 95.7 93.7 92.0
Industrial ..................................... 2.6 2.6 2.5 2.5 2.5 2.5
- ----------------------------------------------------------------------------------------------------------------------------------
Total .................................... 1,394.5 1,353.0 1,315.7 1,280.9 1,248.4 1,218.5
==================================================================================================================================
Sales, Per Average Residential Customer
Gas sold (therms) .............................. 904 733 825 847 794 729
Revenue (dollars) .............................. 550.00 488.32 576.61 556.52 499.65 489.50
Revenue per therm (cents) ...................... 60.8 66.6 69.9 65.7 62.9 67.1
Degree Days -- Atlanta Area
30-year normal ................................. 2,991 2,991 2,991 3,021 3,021 3,021
Actual ......................................... 3,191 2,121 2,565 2,852 2,552 2,273
Percentage of actual to 30-year normal ......... 106.7 70.9 85.8 94.4 84.5 75.2
Gas Account (millions of therms)
Natural gas purchased .......................... 1,632.9 1,406.9 1,453.6 1,629.9 1,555.4 1,563.0
Natural gas withdrawn from storage ............. 596.0 520.7 500.3 276.4 263.3 148.2
Gas transported ................................ 738.7 722.8 697.4 795.6 901.8 862.6
- ----------------------------------------------------------------------------------------------------------------------------------
Total send-out ........................... 2,967.6 2,650.4 2,651.3 2,701.9 2,720.5 2,573.8
Less
Unaccounted for .............................. 60.4 20.4 37.2 29.0 16.2 24.4
Company use .................................. 15.3 10.4 9.9 8.7 8.2 9.4
- ----------------------------------------------------------------------------------------------------------------------------------
Sold and transported to utility customers 2,891.9 2,619.6 2,604.2 2,664.2 2,696.1 2,540.0
==================================================================================================================================
Cost of Gas (millions of dollars)
Natural gas purchased .......................... $ 547.1 $ 389.4 $ 550.1 $ 595.7 $ 487.9 $ 502.5
Natural gas withdrawn from storage ............. 171.6 182.4 186.7 105.3 102.6 77.4
- ----------------------------------------------------------------------------------------------------------------------------------
Cost of gas-- utility operations ............... 718.7 571.8 736.8 701.0 590.5 579.9
- ----------------------------------------------------------------------------------------------------------------------------------
Cost of gas -- other ........................... 1.6
- ----------------------------------------------------------------------------------------------------------------------------------
Total cost of gas ........................ $ 720.3 $ 571.8 $ 736.8 $ 701.0 $ 590.5 $ 579.9
==================================================================================================================================
Utility Plant -- End of Year (millions of dollars)
Gross plant .................................... $ 1,969.0 $ 1,919.9 $ 1,833.2 $ 1,740.6 $ 1,634.8 $ 1,517.0
Net plant ...................................... $ 1,361.2 $ 1,336.6 $ 1,279.6 $ 1,217.9 $ 1,157.4 $ 1,081.4
Gross plant investment per customer
(thousands of dollars) ....................... $ 1.4 $ 1.4 $ 1.4 $ 1.4 $ 1.3 $ 1.2
Capital Expenditures (millions of dollars) ....... $ 132.5 $ 121.7 $ 122.5 $ 122.2 $ 132.9 $ 141.9
Gas Mains-- Miles of 3" Equivalent ............... 29,045 28,520 27,972 27,390 26,936 26,623
Employees-- Average .............................. 2,942 3,249 3,764 3,764 3,794 3,820
Average Btu Content of Gas ....................... 1,024 1,027 1,032 1,027 1,024 1,025
==================================================================================================================================
</TABLE>
<PAGE>
Shareholder Information
Stock Listing
AGL Resources Inc.'s common stock is traded on the New York Stock Exchange
(NYSE) under the symbol ATG. It appears in newspaper financial section stock
listings as AGL Res.
Ownership
Approximately 55.7 million outstanding shares of AGL Resources' common stock are
owned by 16,760 shareholders of record in 50 states, the District of Columbia
and eleven foreign countries.
Market Prices and Dividends
The following table reflects the quarterly high and low closing sales prices, as
reported in the listing of the NYSE composite transactions for shares of common
stock for fiscal 1996 and 1995, and the quarterly dividends paid per share.
Dividends
Paid
Quarter Ended High Low Per Share
- -----------------------------------------------------------------
1996
September 30, 1996 .... $ 20.88 $ 17.38 $ .265
June 30, 1996 ......... 19.00 17.13 .265
March 31, 1996 ........ 20.25 17.63 .265
December 31, 1995 ..... 19.88 18.88 .265
- -----------------------------------------------------------------
1995
September 30, 1995 .... $ 17.63 $ 15.19 $ .26
June 30, 1995 ......... 18.25 16.81 .26
March 31, 1995 ........ 19.31 17.06 .26
December 31, 1994 ..... 19.44 17.31 .26
=================================================================
Annual Meeting
The 1997 Annual Meeting of Shareholders will be held February 7, 1997, at AGL
Resources' offices, 303 Peachtree Street, N.E., Atlanta, Georgia. Proxies for
the meeting of shareholders are being solicited by the Board of Directors. A
formal notice of the meeting, proxy statement and proxy card have been mailed
with the 1996 Annual Report.
Shareholder Reports, Form 10-K and Inquiries
Additional copies of this report and the Form 10-K Annual Report to the
Securities and Exchange Commission (excluding exhibits) can be obtained by
writing to or calling the Corporate Secretary's Office, AGL Resources Inc., Post
Office Box 4569, Atlanta,GA 30302-4569, (404) 584-3794. Shareholder inquiries
also may be directed to the Corporate Secretary's office or to our toll-free
shareholder service number: (800) 633-4236.
Dividend Reinvestment and Stock Purchase Plan
AGL Resources' Dividend Reinvestment and Stock Purchase Plan provides common
shareholders with an economical and convenient method for purchasing additional
shares of common stock without paying any brokerage fees or service charges.
Dividends reinvested through the plan are used to purchase shares of common
stock directly from AGL Resources. For a plan prospectus and enrollment
application, shareholders should contact Wachovia Shareholder Services at the
address below.
Transfer Agent, Registrar and Dividend Disbursing
Agent AGL Resources' transfer agent is Wachovia Bank of North Carolina, N.A.
Correspondence and requests for transfer should be directed to
Wachovia Shareholder Services
Post Office Box 8217
Boston, MA 02266-8217
(800) 633-4236
Direct deposit of cash dividends and automated stock purchase services are
available from the transfer agent above.
Financial Inquiries
Financial analysts
and professional investment managers are invited to contact
J. Michael Riley
Vice President and Chief Financial Officer
AGL Resources Inc.
Post Office Box 4569
Atlanta, GA 30302-4569
(404) 584-3954
<PAGE>
OFFICERS OF AGL RESOURCES INC. AND SUBSIDIARIES
EXECUTIVE OFFICERS OF AGL RESOURCES INC.
David R. Jones (36) President and Chief Executive Officer
Charles W. Bass (26) Executive Vice President and Chief Operating Officer
Thomas H. Benson (26) Executive Vice President, and
Chief Operating Officer of Atlanta Gas Light Company
Robert L. Goocher (24) Executive Vice President, and
Chief Operating Officer of AGL Resources Service
Company
GENERAL OFFICERS OF AGL RESOURCES INC.
Stephen J. Gunther (11) Vice President, and
President 0f AGL Energy Services, Inc.
Clayton H. Preble (26) Vice President, and
President of The Energy Spring, Inc.
Richard H. Woodward (26) Vice President, and
President of AGL Investments, Inc.
Peter L. Banks (14) Vice President, External Affairs
Mark D. Caudill (4) Vice President, Regulatory Affairs
H. Edwin Overcast (7) Vice President, Strategic Planning and Rates
Melanie M. Platt (1) Corporate Secretary
J. Michael Riley (23) Vice President and Chief Financial Officer
James S. Thomas, Jr. (10) Vice President, Legal
ATLANTA GAS LIGHT COMPANY
Isaac Blythers (23) Vice President, Metro Region
Jerry B. Brown (21) Vice President, Georgia Region
Michael D. Hutchins (23) Vice President, Operations and Engineering
Charlie J. Lail (32) Senior Vice President, Operations Improvement
Catherine Land-Waters (14) Vice President, Customer Service
AGL RESOURCES SERVICE COMPANY
Verlene P. Cobb (33) Vice President, Corporate Communications
James W. Connally (26) Vice President, Human Resources
Gerald A. Hinesley (17) Controller
John H. Mobley, Jr. (1) Vice President, Information Systems
Charles C. Moore, Jr. (28) Treasurer
Marvin M. Wyatt, Jr. (26) Vice President, Operations Support
CHATTANOOGA GAS COMPANY
Harrison F. Thompson (26) President
Number in parentheses denotes full years of service as of September 30, 1996.
<PAGE>
Graph appearing on page 22 reflects consolidated operating revenues, operating
expenses and operating expenses as a percentage of operating revenues for the
fiscal years ended September 30,1994 through 1996, inclusive. Data presented is
as follows:
In millions of dollars 1994 1995(a) 1996
- -------------------------------------------------
Operating Revenues 1,200 1,063 1,220
Operating Expenses 1,058 970 1,058
%Operating Expenses to
Operating Revenues 88% 91% 87%
- -------------------------------------------------
(a) Operating expenses include restructuring costs of $70.3 million
Graph appearing on page 22 reflects common stock market value, book value and %
market to book value for the fiscal years ended September 30, 1994, through
1996, inclusive. Data presented is as follows:
In dollars per share 1994 1995 1996
- -------------------------------------------------
Market value per share $15.31 $19.31 $19.13
Book value per share 10.20 10.15 10.56
% market value to book
value 150% 190% 181%
- -------------------------------------------------
<PAGE>
AGL RESOURCES INC.
FORM 10-K FOR THE YEAR ENDED SEPTEMBER 30, 1996
Subsidiaries of the Registrant
AGL Resources has five active wholly owned subsidiaries: Atlanta Gas
Light Company; AGL Resources Service Company; AGL Energy Services, Inc.; AGL
Investments, Inc.; and The Energy Spring, Inc.
AGL Resources has eight active second tier subsidiaries. Following is a
listing of the second tier subsidiaries, together with the respective parent
subsidiaries:
Atlanta Gas Light Company
Chattanooga Gas Company
AGL Energy Services, Inc.
Georgia Gas Company
AGL Investments, Inc.
AGL Consumer Services, Inc.
Georgia Gas Service Company
AGL Gas Marketing, Inc.
AGL Power Services, Inc.
Georgia Energy Company
Trustees Investments, Inc.
Financial statements of the subsidiaries are included in the
consolidated financial statements which are a part of AGL Resources' Form 10-K.
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Registration Statement Nos.
33-31674, 33-36231, 33-50301, 33-62155, 33-52907, 333-01519, and 333-02353 on
Forms S-8 and Registration Statement No. 33-52905 on Form S-3 of our reports
dated November 5, 1996, appearing and incorporated by reference in this Annual
Report on Form 10-K of AGL Resources Inc. for the year ended September 30, 1996.
/S/ DELOITTE & TOUCHE LLP
DELOITTE & TOUCHE LLP
Atlanta, Georgia
December 23, 1996
<TABLE> <S> <C>
<ARTICLE> UT
<CIK> 0001004155
<NAME> AGL RESOURCES INC.
<MULTIPLIER> 1,000,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> SEP-30-1996
<PERIOD-START> OCT-01-1995
<PERIOD-END> SEP-30-1996
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 1,361
<OTHER-PROPERTY-AND-INVEST> 54
<TOTAL-CURRENT-ASSETS> 289
<TOTAL-DEFERRED-CHARGES> 104
<OTHER-ASSETS> 16
<TOTAL-ASSETS> 1,825
<COMMON> 278
<CAPITAL-SURPLUS-PAID-IN> 171
<RETAINED-EARNINGS> 139
<TOTAL-COMMON-STOCKHOLDERS-EQ> 588
56
3
<LONG-TERM-DEBT-NET> 555
<SHORT-TERM-NOTES> 152
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 0
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 471
<TOT-CAPITALIZATION-AND-LIAB> 1,825
<GROSS-OPERATING-REVENUE> 1,220
<INCOME-TAX-EXPENSE> 48
<OTHER-OPERATING-EXPENSES> 720
<TOTAL-OPERATING-EXPENSES> 1,058
<OPERATING-INCOME-LOSS> 162
<OTHER-INCOME-NET> 14
<INCOME-BEFORE-INTEREST-EXPEN> 129
<TOTAL-INTEREST-EXPENSE> 49
<NET-INCOME> 76
4
<EARNINGS-AVAILABLE-FOR-COMM> 76
<COMMON-STOCK-DIVIDENDS> 59
<TOTAL-INTEREST-ON-BONDS> 42
<CASH-FLOW-OPERATIONS> 82
<EPS-PRIMARY> 1.37
<EPS-DILUTED> 1.37
</TABLE>
<PAGE>
EXHIBIT 4
<TABLE>
<S> <C>
[NUMBER] [SHARES]
[ATG] [ ]
COMMON STOCK COMMON STOCK
Par Value $5.00 Par Value $5.00
AGL RESOURCES INC.
CUSIP 001204 10 6
SEE REVERSE FOR CERTALLY DEFINITIONS
This Certificate is THIS CERTIFIES THAT
Transferable to
Boston, Mass.,
New York, N.Y. or
Winston-Salem, N.C.
Incorporated Under
the Laws of the State
of Georgia
IS THE OWNER OF
FULLY PAID AND NON-ASSESSABLE SHARES OF THE COMMON STOCK OF
AGL Resources Inc., transferrable on the books of the Corporation by the holder hereof in person or by
duly authorized attorney upon surrender of this certificate properly endorsed. This certificate is not
valid until countersigned by the Transfer Agent and registered by the Registrar.
Witness the fascimile seal of the Corporation and the fascimile signatures of its duly authorized
officers.
[SEAL] Dated:
/s/ Melanie McGee Platt [LOGO] AGL Resources Inc. /s/ David L. Jones
Corporate Secretary President
Countersigned and Registered
WACHOVIA BANK OF NORTH CAROLINA, N.A.
(Winston-Salem, N.C.)
Transfer Agent and Registrar
Authorized Signature
</TABLE>
<PAGE>
This certificate also evidences and entitles the holder hereof to certain
rights as set forth in a Rights Agreement between AGL Resources Inc., a Georgia
Corporation, and Wachovia Bank of North Carolina, N.A., a North Carolina
corporation, dated as of March 6, 1996 as the same may be amended from time to
time (the "Rights Agreement"), the terms of which are hereby incorporated
herein by reference and a copy of which is on file at the prinicipal executive
offices of AGL Resources Inc. Under certain circumstances, as set forth in the
Rights Agreement, such Rights will be evidenced by separate certificates and
will no longer be evidenced by this certificate. AGL Resouces Inc. will mail
to the holder of this certificate a copy of the Rights Agreement without charge
after receipt of a written request thereof. Under certain circumstances, as
set forth in the Rights Agreement, Rights owned by or transferred to any Person
who becomes an Acquiring Person (as definded in the Rights Agreement) and
certain transferees thereof will become null and void and will no longer be
transferable.
AGL RESOURCES INC.
THE CORPORATION WILL FURNISH TO THE HOLDER HEREOF UPON REQUEST IN
WRITING AND WITHOUT CHARGE, A FULL STATEMENT OF THE DESIGNATIONS, PREFERENCES,
LIMITATIONS AND RELATIVE RIGHTS, AND THE VARIATIONS IN RELATIVE RIGHTS AND
PREFERENCES, OF EACH CLASS OF STOCK OR SERIES THEREOF WHICH THE CORPORATION IS
AUTHORIZED TO ISSUE, TOGETHER WITH THE AUTHORITY OF THE BOARD OF DIRECTORS OR
SHAREHOLDERS TO FIX AND DETERMINE THE RELATIVE RIGHTS AND PREFERENCES OF
SUBSEQUENT CLASSES AND SERIES.
The following abbreviations, when used in the inscription on the face
of this certificate, shall be construed as though they were written out in full
according to applicable laws or regulations:
<TABLE>
<S> <C>
TEN COM - as tenants in common UNIF GIFT MIN ACT..........Custodian...........
TEN ENT - as tenants by the entireties (Cust) (Minor)
JT TEN - as joint tenants with right of under Uniform Gifts to Minors
survivorship and not as tenants Act...........................
in common (State)
Additional abbreviations may also be used though not in the above list
For value received...............................hereby sell, assign and transfer unto
PLEASE INSERT SOCIAL SECURITY OR OTHER
IDENTIFYING NUMBER OF ASSIGNEE
[ ]..............................................................
....................................................................................................
Please print or typewrite name and address including postal zip code of assignee
....................................................................................................
............................................................................................. Shares
of the capital stock represented by the within certificate, and do hereby irrevocably constitute and
appoint.............................................................................................
....................................................................................................
Attorney to transfer the said stock on the books to the within-named Corporation with full power of
substitution in the premises.
Dated:.............................................
</TABLE>
<PAGE>
EXHIBIT 10.1.a
EXECUTIVE SEVERANCE PAY PLAN
OF AGL RESOURCES INC.
----------------------------
Introduction
AGL Resources Inc., a Georgia corporation (the "Company"), hereby
establishes the Executive Severance Pay Plan of AGL Resources Inc., effective
as of May 15, 1996, to provide certain executives of the Company or its
Subsidiaries with severance benefits in the event of specific types of
Terminations as (hereinafter defined) which occur within twelve months after a
Change in Control (as hereinafter defined).
Section 1. Definitions
1.1 "Board" means the Board of Directors of the Company.
1.2 "Bonus" means the highest aggregate amount of bonuses paid in
any calendar year to a Named Executive under the Company's Variable
Companesation Plan and/or any other cash bonus plans during the three (3)
calendar years preceding any Change in Control.
1.3 "Cause" means (i) the Named Executive's continued failure to
substantially perform the duties and responsibilities of the Named Executive's
office after written notice from the Company setting forth the particulars of
such failure and a reasonable opportunity, but not less than ten (10) business
days to cure; (ii) the Named Executive's fraud, dishonesty or willful
malfeasance in connection with the Named Executive's employement with the
Company which results in material harm to the Company; or (iii) the Named
Executive's plea of guilty or nolo contendere to, or nonappealable conviction
of, a felony, in each of (i) through (iii) above, upon 30 days written notice
to the Named Executive to be heard by the Board and the good faith
determination by at least two-thirds of the Company's non-employee directors
that Cause exists.
1.4 "Change in Control" shall be deemed to have occurred when:
(i) any "person" as defined in Section 3(a)(9) of the
Securities Exchange Act of 1934, as amended (the "Exchange Act"), and
as used in Section 13(d) and 14(d) thereof, including a "group" as defined
in Section 13(d) of the Exchange Act but excluding the Company and any
subsidiary and any employee benefit plan sponsored or
<PAGE>
2
maintained by the Company or any subsidiary (including any trustee of such plan
acting as trustee), directly or indirectly, becomes the "beneficial owner" (as
defined in Rule 13d-3 under the Exchange Act), of securities of the Company
representing 10% or more of the combined voting power of the Company's then
outstanding securities (unless the event causing the 10% threshold to be
crossed is an acquisition of securities directly from the Company); or
(ii) the shareholders of the Company shall approve any merger or other
business combination of the Company, sale of 50% or more of the Company's
assets or combination of the foregoing transactions (the "Transactions") other
than a Transaction immediately following which the shareholders of the Company
and any trustee or fiduciary of any Company employee benefit plan immediately
prior to the Transaction owns at least 80% of the voting power, directly or
indirectly, of (A) the surviving corporation in any such merger or other
business combination; (B) the purchaser of the Company's assets; (C) both the
surviving corporation and the purchaser in the event of any combination of
Transactions; or (D) the parent company owning 100% of such surviving
corporation, purchaser or both the surviving corporation and the purchaser, as
the case may be; or
(iii) within any twenty-four month period, the persons who were
directors immediately before the beginning of such period (the "Incumbent
Directors") shall cease (for any reason other than death) to constitute at
least a majority of the Board or the board of directors of a successor to the
Company. For this purpose, any director who was not a director at the
beginning of such period shall be deemed to be an Incumbent Director if such
director was elected to the Board by, or on the recommendation of or with the
approval of, at lease two-thirds of the directors who then qualified as
Incumbent Directors (so long as such director was not nominated by a person who
has entered into an agreement to effect a Change in Control or expressed an
intention to cause such a Change in Control).
1.5. "Code" means the Internal Revenue Code of 1986, as amended.
1.6. "Committee" means the Compensation Committee appointed by the
Board, or in lieu of such Committee, the Board's designee.
1.7. "Company" means AGL Resources Inc., a corporation incorporated
under the laws of the State of Georgia.
<PAGE>
3
1.8. "Compensation" means the amount per annum that a Named Executive
was paid or provided by the Company as base salary or wages (including any
amounts received under the Company's Executive Allowance Fund, but excluding
all bonuses, commissions, overtime, and other forms of special or incentive
remuneration) immediately prior to (i) the date of Termination or (ii) if
higher, the date of the Change in Control.
1.9. "Disability" means the Named Executive's absence from full-time
performance of the Named Executive's duties pursuant to a determination made in
accordance with the procedures established by the Company in connection with
the Company's long-term disability benefits plan, which plan was in effect
immediately prior to the Change in Control, that the Named Executive is
disabled as a result of incapacity due to physical or mental illness.
1.10. "Employer" means the Company and any of its subsidiaries which
employs a Named Executive.
1.11. "Good Reason" shall mean the occurrence, within 12 months after
a Change in Control, of any of the following without the Named Executive's
express written consent:
(i) any material diminution in the Named Executive's position, duties
or responsibilities with the Company from those in effect immediately prior
to the Change in Control or which would constitute a material adverse
alteration in the Named Executive's duties, responsibilities or other
conditions of employment from those in effect immediately prior to the
Change in Control; or
(ii) any adverse change in the Named Executive's salary and incentive
compensation from the salary and incentive compensation in effect
immediately prior to the Change in Control; or
(iii) any failure by the Company either to continue in effect, or to
provide reasonably similar retirement, savings, medical, dental,
accident, disability and life insurance plans and any other similar
benefits, policy or program in which the Named Executive was a participant
immediately prior to the Change in Control; or
(iv) any relocation of the Named Executive's employment to a location
in excess of 35 miles from the location at which the Named Executive was
based immediately prior to the Change in Control.
<PAGE>
4
1.12 "Named Executive" means any individual named by the Committee as
shown on Schedule 1 attached hereto.
1.13 "Month" means the period of time starting on a date in any
calendar month and continuing until the day before the corresponding date in
the next calendar month.
1.14 "Notice of Termination" means a written notice which shall
indicate the specific termination provision in this Plan relied upon and shall
set forth in reasonable detail the facts and circumstances claimed to provide a
basis for termination of the Named Executive's employment under the provisions
so indicated. For purposes of this Plan, no purported termination shall be
effective without such Notice of Termination having been given.
1.15 "Parachute Payment" means any payment deemed to constitue a
"parachute payment" as defined in Section 280G of the Code.
1.16 "Plan" means this Executive Severace Pay Plan of AGL Resources
Inc., as set forth in this document, as amended from time to time.
1.17 "Potential Change in Control" shall be deemed to have occurred
if.
(i) any "person" as definded in Section 3 (a) (9) of the Securities
Exchange Act of 1934, as amended (the "Exchange Act"), and as used in Section
13(d) and 14(d) thereof, including a "group" as defined in Section 13(d) of the
Exchange Act but excluding the Company and any subsidiary and any employee
benefit plan sponsored or maintained by the Company or any subsidiary
(including any trustee of such plan acting as trustee), commences a tender
offer for securities of the Company representing 10% or more of the combined
voting power of the Company's then outstanding securities; or
(ii) the Company enters into an agreement the consummation of which
will constitute a Change in Control; or
(iii) proxies for the election of directors are solicited by anyone
other than the Company; or
(iv) any other event occurs which is deemed to be a Potential Change
in Control by the Board.
1.18 "Severance Pay" means the amounts, if any, payable under Section
3.1 of this Plan to a Named Executive upon Termination.
<PAGE>
5
1.19 "Termination" means a Named Executive's involuntary termination
of employment with the Employer without Cause or voluntary termination by the
Named Executive for Good Reason within twelve (12) months after the occurence
of a Change in Control. Termination shall not include any termination of
employment by reason of death, Disability or voluntary (normal) retirement of
the Named Executive.
Section 2. Eligibility
2.1 Any salaried employee who performs a key function for the Company
shall be eligible to be designated as a Named Executive and each Named
Executive shall participate in the Plan. The Committee may, from time to time,
add or remove individuals as Named Executives; provided, however, in no event
shall the Committee remove any individual after a Potential Change in Control
or a Change in Control.
Section 3. Benefits
3.1 Severance. As soon as practicable after the date of Termination,
but in any event no later than 10 business days following such termination, the
Company shall pay or cause to be paid to the Named Executive, a lump sum cash
amount equal to the sum of (i) the Compensation and (ii) the Bonus. In
addition, at the time of the above payment, the Named Executive shall be
entitled to an additional lump sum cash payment equal to the sum
<PAGE>
6
of (i) the Compensation and (ii) the Bonus, multiplied by a fraction, the
numerator of which is the appropriate "Additional Months" from the schedule
below and the denominator of which is 12.
<TABLE>
<CAPTION>
================================================================================
IF, FOLLOWING A CHANGE IN CONTROL,
SUCH TERMINATION OCCURS ADDITIONAL MONTHS
- --------------------------------------------------------------------------------
<S> <C>
Within the first month 12
Within the second month 11
Within the third month 10
Within the fourth month 9
Within the fifth month 8
Within the sixth month 7
Within the seventh month 6
Within the eighth month 5
Within the ninth month 4
Within the tenth month 3
Within the eleventh month 2
Within the twelfth month 1
After the twelfth 0
================================================================================
</TABLE>
3.2 Additional Payments and Benefits. The Named Executive shall be
entitled to (i) continued medial, dental and life insurance coverage for the
named Executive and the Named Executive's eligible dependents on the same basis
as in effect prior to the Change in control or the Named Executive's
Termination of employment, whichever is deemed to provide for more substantial
benefits, until the earlier of (A) twelve (12) months after the Named
Executive's Termination or (B) the commencement of comparable coverage with a
subsequent employer; provided, however, that such continued coverage shall not
count against any continued coverage required by law; (ii) immediate 100%
vesting of all outstanding stock options, stock appreciation rights and
restricted stock, (iii) payment of pro rata target bonus under each of the
Company's bonus plans, based on the number of days employed or, if greater, the
full actual bonus earned under such bonus plan through the date of employment
Termination; and (iv) a lump sum cash amount equal to the difference between
(A) the actuarial equivalent of the additional benefit that would have accrued
under the Company's retirement
<PAGE>
7
plans if the Named Executive's employment continued for a period of twelve (12)
months from the date of Termination, and (B) the actuarial equivalent of the
Named Executive's actual retirement benefits. In determining the actuarial
value for purposes hereof, the actuarial assumptions and methods used in the
Company's retirement plans shall be utilized. In the event that there is any
issue concerning the application of such assumptions or methods, the Company
shall in good faith make any reasonable determination or decision necessary to
resolve such discrepancy. Any payment of additional benefits pursuant to this
Section 3.2(iv) shall be paid from assets of the Company, not from assets of
any retirement plan.
3.3 Outplacement. If so requested by the Named Executive,
outplacement services shall be provided by a professional outplacement
provider, in accordance with existing Company policy, but in not event shall
such services be less than under Company policy prior to the Change in Control;
provided, however, if the Company has no such policy, such outplacement
services shall be provided at a cost to the Company of not more than 25% of the
Named Executive's Compensation.
3.4 Withholding. Payments and benefits provided pursuant to this
Section 3 shall be subject to any applicable payroll and other taxes required
to be withheld.
3.5 Parachute Payment Limitation. If any payment or benefit to the
Named Executive under this Plan would be considered a "parachute payment"
within the meaning of Section 280G(b)(2) of the Internal Revenue Code of 1986,
as amended (the "Code") and if, after reduction for any applicable federal
excise tax imposed by Code Section 4999 (the "Excise Tax") and federal income
tax imosed by the Code, the Named Executive's net proceeds of the amounts
payable and the benefits provided under this plan would be less than the amount
of the Named Executives net proceeds resulting from the payment of the Reduced
Amount described below, after reduction for federal income taxes, then the
amount payable and the benefits provided under this Plan shall be limited to
the Reduced Amount. The "Reduced Amount" shall be the largest amount that
could be received by the Named Executive under this Plan such that no amount
paid to the Named Executive under this Plan and any other agreement, contract,
or understanding heretofore or hereafter entered into between the Named
Executive and the Company (the "Other Agreements") and any formal or informal
plan or other arrangement heretofore or hereafter adopted by the Company for
the direct or indirect provision of compensation to the Named Executive
(including groups or classes of participants or beneficiaries of which the
Named Executive is a member), whether or not such compensation is deferred, is
in cash; or is in the form of a benefit to or for
<PAGE>
8
the Named Executive (a "Benefit Plan") would be subject to the Excise Tax. The
Reduced Amount shall be calculated by a nationally recognized benefit
consulting or accounting firm (the "Firm"), which amount shall be presented to
the Named Executive for review and approval. In the event that the amount
payable to the Named Executive shall be limited to the Reduced Amount, then the
Named Executive shall have the right, in the Named Executive's sole discretion,
to designate those payments or benefits under this Plan, any Other Agreements,
and/or any Benefit Plans, that should be reduced or eliminated so as to avoid
having the payment to the Named Executive under this Plan be subject to the
Excise Tax.
In the event that the Internal Revenue Service claims that any payment
or benefit received under this Plan constitutes an "excess parachute payment,"
within the meaning of Section 280G(b) (1) of the Code, the Named Executive
shall notify the Company in writing of such claim. Such notification shall be
given as soon as practicable but no later than 10 business days after the Named
Executive is informed in writing of such claim and shall apprise the Company of
the nature of such claim and the date on which such claim is requested to be
paid. The Named Executive shall not pay such claim prior to the expiration of
the 30 day period following the date on which the Named Executive gives such
notice to the Company (or such shorter period ending on the date that any
payment of taxes with respect to such claim is due). If the Company notifies
the Named Executive in writing prior to the expiration of such period that it
desires to contest such claim, the Named Executive shall (i) give the Company
any information reasonably requested by the Company relating to such claim;
(ii) take such action in connection with contesting such claim as the Company
shall reasonably request in writing from time to time, including without
limitation, accepting legal representation with respect to such claim by an
attorney reasonable selected by the Company and reasonably satisfactory to the
Employee; (iii) cooperate with the Company in good faith in order to effectively
contest such claim; and (iv) permit the Company to participate in any
proceedings relating to such claim; provided, however, that the Company shall
bear and pay directly all costs and expenses (including, but not limited to,
additional interest and penalties and related legal, consulting or other
similar fees) incurred in connection with such contest and shall indemnify and
hold the Named Executive harmless, on a after-tax basis, for any Excise Tax or
other tax (including interest and penalties with respect thereto) imposed as a
result of such representation and payment of costs and expenses.
The Company shall control all proceedings taken in connection with such
contest and, at its sole option, may pursue or forgo any and all administrative
appeals, proceedings,
<PAGE>
9
hearings and conferences with the taxing authority in respect of such claim and
may, at its sole option, either direct the Named Executive to pay the tax
claimed and sue for a refund or contest the claim in any permissible manner, and
the Named Executive agrees to prosecute such contest to a determination before
any administration tribunal, in a court of initial jurisdiction and in one or
more appellate courts, as the Company shall determine; provided, however, that
if the Company directs the Named Executive to pay such claim and sue for a
refund, the Company shall advance the amount of such payment to the Named
Executive on an interest-free basis, and shall indemnify and hold the Named
Executive harmless, on an after-tax basis, from any Excise Tax or other tax
(including interest and penalties with respect thereto) imposed with respect to
such advance or with respect to any imputed income with respect to such
advance; and provided, further, that if the Named Executive is required to
extend the statute of limitations to enable the Company to contest such claim,
the Named Executive may limit this extension solely to such contested amount.
The Company's control of the contest shall be limited to issues with respect to
which a corporate deduction would be disallowed pursuant to Section 280G of the
Code and the Named Executive shall be entitled to settle or contest, as the
case may be, any other issue raised by the Internal Revenue Service or any
other taxing authority. In addition, no position may be taken nor any final
resolution be agreed to by the Company without the Named Executive's consent if
such position or resolution could reasonably be expected to adversely affect
the Named Executive (including any other tax position of the Named Executive
unrelated to matters covered hereby).
If, after the receipt by the Named Executive of an amount advanced
by the Company in connection with the contest of the Excise Tax Claim, the
Named Executive becomes entitled to receive any refund with respect to such
claim, the Named Executive shall promptly pay to the Company the amount of such
refund (together with any interest paid or credited thereon after taxes
applicable thereto); provided, however, if the amount of that refund exceeds the
amount advanced by the Company or it is otherwise determined for any reason
that additional amounts could be paid to the Named Executive without incurring
any Excise Tax, any such amount will be promptly paid by the Company to the
Named Executive. If, after the receipt by the Named Executive of an amount
advanced by the Company in connection with an Excise Tax claim, a determination
is made that the Named Executive shall not be entitled to any refund with
respect to such claim and the Company does not notify the Named Executive in
writing of its intent to contest the denial of such refund prior to the
expiration of 30 days after such determination, such advance shall be forgiven
and shall not be required to be repaid and
<PAGE>
10
shall be deemed to be in consideration for services rendered after the
Termination.
3.6. Nonqualified Retirement and Deferral Plan Benefits.
Through an a agreement (the "Trust Agreement") with any corporate Trustee
selected by the Company and reasonably acceptable to a majority in interest of
Named Executives (the "Trustee"), the Company shall establish an irrevocable
rabbi trust (the "Trust") to hold assets in reserve for the discharge of the
Company's obligations to each Named Executive under the Excess Benefits Plan
and any other nonqualified retirement or deferred compensation plan for which
no Rabbi Trust has already been established (the "Plans") in the event that a
Change in Control occurs. Upon execution of the Trust Agreement, the Company
shall deliver cash in an amount necessary to establish a trust under applicable
laws to the Trustee to be held uninvested prior to a Change in Control. After
a Change in Control, the Trustee shall not be changed without the written
consent of a majority in interest of Named Executive.
Upon a Change in Control, all benefits of the Plans shall become 100% vested
and funded in the Trust. Within 15 business days after a Change in Control,
the Company shall deliver to the Trustee a contribution of cash or cash
equivalents in an amount equal to the present value of the Named Executive's
accrued benefits under the Plans. In addition, the Company shall deliver to
the Trustee payment schedules indicating either the amounts payable, to, or on
behalf of, the Named Executive or providing a formula or instructions for
determining the amounts so payable, the person or persons to whom payable, the
form in which sum amounts are to be paid (in accordance with the terms of the
Plans) and the time of the commencement of the payment of such benefits. In
years following the Change in Control, the Company shall deliver to the trustee
annual contributions in an amount necessary to maintain the Trust's fully
funded status. All contributions to the Trust shall be invested in accordance
with the terms of the Trust Agreement.
The principal of the Trust, and any earnings thereon, shall be held separate
and apart from other funds of the Company and shall be used exclusively for the
uses and purposes of each Named Executive and general creditors. The Named
Executive and his Beneficiaries shall have no preferred claim on, or any
beneficial ownership interest in, any assets of the Trust. Any assets held by
the Trust will be subject to the claims of the Company's general creditors
under federal and state law in the event of insolvency.
<PAGE>
11
Section 4. Administration of the Plan
4.1. (a) The Committee shall be the Plan administrator. In addition
to any other powers granted to the Committee under the Plan, the Committee
shall have the exclusive right, power and authority to interpret, in its sole
discretion, any and all of the provisions of the Plan; to establish claims and
appeals procedures in accordance with Section 4.1(b) below; and to consider and
decide conclusively any questions (whether of fact or otherwise) arising in
connection with the administration of the Plan or any claim for Severance Pay
arising under the Plan, including, without limitation, the determination of a
termination for Cause. Any decision or action of the Committee shall be final,
conclusive and binding on all interested parties.
(b) If any Named Executive believes he is entitled to benefits in an
amount greater than those which he is receiving or has received, he may file a
claim with the Committee. Such a claim shall be in writing and state the
nature of the claim, the facts supporting the claim, the amount claimed, and
the address of the claimant. The Committee shall review the claim and, unless
special circumstances require an extension of time, within 90 days after
receipt of the claim, given written notice by registered or certified mail to
the claimant of the Committee's decision with respect to the claim. If special
circumstances require an extension of time, the claimant shall be so advised in
writing within the initial 90-day period and in no event shall such an
extension exceed 90 days. The notice of the Committee's decision with respect
to the claim shall be written in a manner intended to be understood by the
claimant and, if the claim is wholly or partially denied, set forth the
specific reasons for the denial, specific references to the pertinent Plan
provisions on which the denial is based, a description of any additional
material or information necessary for the claimant to perfect the claim, an
explanation of why such material or information is necessary, and an
explanation of the claim review procedure under the Plan. The Committee shall
also advise the claimant that he or his duly authorized representative may
request a review by the Committee of the denial by filing with the Committee,
within 60 days after notice of the denial has been received by the claimant, a
written request for such review. The claimant shall be informed that he may
have reasonable access to pertinent documents and submit comments in writing to
the Committee within the same 60-day period. If a request is so filed, review
of the denial shall be made by the Committee within, unless special
circumstances require an extension of time, 60 days after receipt of such
request, and the claimant shall be given written notice of the final decision.
If special circumstances require an extension of time, the claimant shall be so
advised in writing
<PAGE>
12
within the 60-day period and in no event shall such an extension exceed 60
days. The notice of the final decision shall include specific reasons for the
decision and specific references to the pertinent Plan provisions on which the
decision is based and shall be written in a manner intended to be understood by
the claimant.
Section 5. Miscellaneous
5.1. The Board reserves the right, upon unanimous written consent or a
majority vote of the directors present, in person or by telephone, at a meeting
of the Board, to modify, amend or terminate the Plan in whole or part, without
notice at any time, and benefits hereunder, whether in an individual case or
more generally, may be altered, reduced, or eliminated by the Board; provided,
however, in no event shall the Board, or any successor to such Board, modify,
amend or terminate the Plan after the a Change in Control or a Potential Change
in Control; provided, however, that the Board may modify, amend or terminate
this Agreement under this Section 5.1 upon (i) a good faith determination by
the Board that the events giving rise to a Potential Change in Control will not
result in the occurrence of a Change in Control or (ii) receipt by the Company
of a written notice from the Named Executive, given after the first anniversary
of the occurrence of a Potential Change in Control (but prior to the occurrence
of Change in Control), that the Named Executive consents to the Board having
the right to modify, amend or terminate the Plan. All modifications of, or
amendments to, the Plan shall be in writing.
5.2. Neither the establishment of the Plan nor any action of the
company, the Committee, or a fiduciary shall be held or construed to confer
upon any person any legal right to continue employment with the Company. The
Company expressly reserves the right to discharge any employee whenever the
interest of the Company, in its sole judgement, may so require, without any
liability, except as provided pursuant to this Plan Document, on the part of
the Company, the Committee, or any fiduciary.
5.3. Benefits payable under the Plan shall be paid out of the general
assets of the Company, and are not required to be funded in any manner,
although the Company may set aside amounts in respect of, or fund benefits
payable hereunder. Benefits payable to a Named Executive will represent an
unsecured claim by such Named Executive against the general assets of the
Company.
5.4. Any payments to a Named Executive under this Plan shall be
reduced by any other payments under any other severance
<PAGE>
13
plan or any other employment agreement which such Named Executive is eligible
to receive.
5.5. Except to the extent required by law benefits payable under the
Plan shall not be subject to assignment, alienation, transfer, pledge, levy,
attachment or other legal process, encumbrance, commutation or anticipation
by the Named Executive and any attempt to do so shall be void.
5.6. This Plan shall be interpreted and applied in accordance with the
laws of the State of Georgia (without reference to rules relating to conflicts
of laws), except to the extent superseded by applicable federal law.
<PAGE>
14
IN WITNESS WHEREOF, the Company has caused this Plan to be executed by
its duly authorized officers and its corporate seal to be affixed hereto, all
as of the date first above written
AGL RESOURCES INC.
By: /s/ David R. Jones
--------------------
Title: President & CEO
Attest: /s/ D. Raymond Riddle
----------------------
Title: Board of Directors
[CORPORATE SEAL]
<PAGE>
15
SCHEDULE I
NAMED EXECUTIVES
IN THE
EXECUTIVE SEVERANCE PAY PLAN
OF AGL RESOURCES INC.
Peter L. Banks
Isaac Blythers
Jerry B. Brown
Mark D. Caudill
Verlene P. Cobb
James W. Connally
Stephen J. Gunther
Michael D. Hutchins
Charlie J. Lail
Catherine Land-Waters
John H. Mobley, Jr.
Charles C. Moore, Jr.
H. Edwin Overcast
Melanie M. Platt
Clayton H. Preble
James M. Riley
James S. Thomas, Jr.
Richard H. Woodward, Jr.
Marvin M. Wyatt, Jr.
<PAGE>
